Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,00024,000 MW of electric generating capacity, including nearly 9,000 MW of nuclear power.capacity. Entergy delivers electricity to 2.9approximately 3 million utilityUtility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $11.1$12.1 billion in 20172023 and had more than 13,000approximately 12,000 employees as of December 31, 2017.2023.
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 9,745,8748,917,149 and 6,017,1746,130,048 Mcf, respectively, of natural gas to retail customers in 2017.2023. In 2017,2023, 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, 88%87% of operating revenue was derived from the electric utility business and 12%13% from the natural gas distribution business in 2017. 2023.
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’companies and System Energy’s 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 | | $7.095 (a) | | 9.25% -10.25% | | 4.67% | | 31.69% | | - forward test year formula rate plan
- riders: MISO, capacity, Grand
Gulf, energy efficiency, fuel and
purchased power | |
| | | | | | | | | | | | |
| Entergy Louisiana (electric) | | $8.303 (b) | | 9.15% - 10.75% | | 7.35% | | 49.64% | | - formula rate plan through 2016 test
year
- riders/specific recovery: MISO,
capacity, fuel | |
| | | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.059 (c) | | 9.45% - 10.45% | | 7.54% | | 51.63% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | | |
| Entergy Mississippi | | $2.131 (d) | | 9.47% - 11.49% | | 7.35% | | 49.37% | | - formula rate plan with
forward-looking features
- riders: power management, Grand
Gulf, fuel, MISO, unit power cost,
storm damage, energy efficiency, ad
valorem tax adjustment
| |
| | | | | | | | | | | | |
| Entergy New Orleans (electric) | | $0.299 (e) | | 10.7% - 11.5% | | 8.58% | | 50.08% | | - rate case
- riders/specific recovery: fuel, capacity | |
| | | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.089 (f) | | 10.25% - 11.25% | | 8.40% | | 50.08% | | - rate case
- rider: purchased gas | |
| | | | | | | | | | | | |
| Entergy Texas | | $1.634 (g) | | 9.8% | | 8.22% | | 48.6% | | - rate case
- riders: fuel, distribution and transmission, RPCE payments and rate case expenses, among others | |
| | | | | | | | | | | | |
| System Energy | | $1.201 (h) | | 10.94% | | 8.90% | | 65% | | - monthly cost of service | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy New Orleans (electric) | | $1.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity costs |
| Entergy New Orleans (gas) | | $0.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - rider: purchased gas |
| Entergy Texas | | $4.4 (h) | | 9.57% | | 6.61% | | 51.2% | | - rate case and cost recovery riders - riders: fuel, capacity, cost recovery riders (distribution, transmission, and generation), rate case expenses, advanced metering infrastructure surcharge, and tax reform, among others |
| System Energy | | $1.74 (i) | | 10.94% (j) | | 8.54% | | 59.5% (j) | | - monthly cost of service |
| |
(a) | Based on 2018 forward test year. |
| |
(b) | Based on December 31, 2016 test year. |
| |
(c) | Based on September 30, 2016 test year. |
| |
(d) | Based on 2017 forward test year. |
| |
(e) | Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union. |
| |
(f) | Based on December 31, 2011 test year. |
| |
(g) | Based on March 31, 2013 adjusted test year and excludes approximately $331 million for rate base being recovered through the distribution cost recovery rider and the transmission cost recovery rider |
| |
(h) | Based on calculation as of December 31, 2017. |
(a)Based on 2024 test year.
(b)Based on $1.9 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted-average cost of capital calculation.
(c)Based on December 31, 2022 test year and excludes approximately $300 million of transmission plant investment included in the transmission recovery mechanism and approximately $200 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of net accumulated deferred tax liability items included in the tax reform adjustment mechanism.
(d)Based on September 30, 2022 test year.
(e)Based on 2023 forward test year.
(f)Based on December 31, 2022 test year and known and measurables through December 31, 2023.
(g)In October 2023 the City Council approved a three-year extension of Entergy New Orleans’s formula rate plan, modified to reflect a 55% fixed capital structure for rate setting purposes.
(h)Based on December 31, 2021 test year.
(i)Based on calculation as of December 31, 2023.
(j)Effective July 2022, Entergy Mississippi’s bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, and a rate base reduction for the advance collection of sale-leaseback rental costs. See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
Entergy Arkansas
Formula Rate Plan
Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change 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
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2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. As part of the settlement of the 2023 formula rate plan proceeding, Entergy Arkansas agreed to file its next base rate case no later than February 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.
Other
In June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing for a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The APSC approved an initial offering of 100 MW of solar capacity to be made available under this tariff.
In June 2023 the APSC approved Entergy Arkansas’s Go ZERO tariff, which provides participating industrial and commercial customers the opportunity to chose from a number of clean energy options to help them achieve their sustainability goals.
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. In 2021 the LPSC approved a settlement extending the formula rate plan for test years 2020, 2021 and 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and certain distribution investments, among other items. In August
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2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years, test years 2023-2025, which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study, with a 2024-2026 test year formula rate plan. The application complies with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service/rate case. See Note 2 to the financial statements for a discussion of Entergy Louisiana’s application.
Fuel and Purchased Power Cost 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 hedgeshistorically 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 iswas 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. A decision is expectedexposure, 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.
To help stabilize retailRetail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas costs,rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana received approval fromsubmitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC to hedge its exposure to natural gas price volatilitystaff submitted an uncontested settlement that extends the rider for its gas purchased for resale throughan additional ten years beginning after the use of financial instruments. Entergy Louisiana hedges approximately one-halfend of the projected natural gas volumes usedcurrent term of the rider in 2025. The extension is subject to serve its natural gas customers for November through March.the same customer safeguards and conditions as the original term of the rider. The hedge quantity is reviewed on an annual basis.
extension
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allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs, Entergy Louisiana plans to cap the average fuel adjustment charge to be billed in March 2018 at $0.03060 per kWh and to defer billing of all fuel costs in excess of the capped amounts by including such costs in the over- or under-recovery account.
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 recently-approved Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
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.
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.
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 currentthen-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 docket.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
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return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider.
In 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.
In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the annual power management and grid modernization riders effective January 2023.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
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Other
In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule.
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. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.
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.
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.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Due to higher fuel costs for the operating month of January 2018 resulting in part from recent cold weather, higher Henry Hub prices, and an increase in total fuel and purchased power costs associated in part with certain plant outages, Entergy New Orleans has proposed to cap the fuel adjustment charge to be billed in March 2018 to non-transmission Entergy New Orleans legacy customers and Entergy New Orleans Algiers customers at $0.035323 per kWh and $0.025446 per kWh, respectively. Entergy New Orleans has also proposed to cap the fuel adjustment charge to be billed in March 2018 for Entergy New Orleans legacy transmission customers at $0.034609 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s effortsfilings to recover storm-related costs.
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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 and Purchased Power Cost 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-annualHistorically, semi-annual revisions of the fixed fuel factor arehave been 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. TheIn the course of this reconciliation, the PUCT determines whether eligible fuel cost proceedingsand fuel-related expenses and revenues are discussed in Note 2necessary and reasonable and makes a prudence finding for each of the fuel-related contracts entered into during the reconciliation period. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the financial statements.PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.
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.agreements to be recovered through a purchased power capacity rider. No Texas utility, including Entergy Texas, has not exercised the option to recover its capacity costs under the new rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs. In 2023, the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through a purchased power capacity rider.
Transmission, Distribution, and Generation 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 permitted 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. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their
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distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Other
In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.
As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.
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 Entergy Texas’sa qualified power region.
The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filingsregion 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.
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)(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)(2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer”;customer;” and 3)(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.
Entergy Texas and the other parties to the PUCT proceeding to determine the design of the competitive generation tariff were involved in negotiations throughout 2011 and 2012 with the objective of resolving as many disputed issues as possible regarding the tariff. The PUCT determined that unrecovered costs that couldmay be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost
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revenues or embedded generation costs. The PUCT also ruled that the amount of customer load that may be included in the competitive generation service program is limited to 115 MW. After additional negotiations,
System Energy
Cost of Service
The rates of System Energy are established by the FERC, and ultimately the scheduling of a hearingcosts allowed to resolve remaining contested issues, the PUCT issued the order approving the competitive generation service riderbe charged pursuant to these rates are, in July 2013. Entergy Texas filed for rehearing of the PUCT’s July 2013 order, which the PUCT denied. Entergy Texas has since filed its appeal of that PUCT orderturn, passed through to the Travis County District Court, which found in favor of the PUCT in an order issued in October 2014. In November 2014, Entergy Texas appealed the District Court’s order which moves the appeal to the Third Court of Appeals. Entergy
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Texasinvestment in, Grand Gulf. Retail regulators and opposingother parties filed briefs and responsesmay seek to initiate proceedings at FERC to investigate the prudence of costs included in the first quarter 2015. Oral argument was held in May 2015. In March 2016rates 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 (or on appeal from the FERC to the United States Court of Appeals upheldfor the District Court’s ruling favoringFifth Circuit), 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 PUCT. In May 2016,Unit Power Sales Agreement, and two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy Texas filed withcannot predict the Texas Supreme Courtoutcome of any of these proceedings, and an adverse outcome in any of them could have a petitionmaterial adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for reviewfurther discussion of the Court of Appeals ruling. In January 2017, Entergy Texas filed its petitioner’s brief on the merits with the Texas Supreme Court. In June 2017 the Texas Supreme Court denied Entergy Texas’s petition in this matter.proceedings.
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 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.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are terminablegoverned pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric
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service in approximately 6870 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire during 2018-2058.over the period 2024-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2017,2023 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,036 | | | 1,548 | | | 521 | | | 1,825 | | | 969 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,798 | | | 5,594 | | | 2,728 | | | 2,137 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,904 | | | 1,744 | | | 641 | | | — | | | 417 | | | — | | | 102 | |
| Entergy New Orleans | | 662 | | | 635 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,234 | | | 990 | | | 1,994 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,245 | | | — | | | — | | | 1,245 | | | — | | | — | | | — | |
| Total | | 23,879 | | | 10,511 | | | 5,884 | | | 5,207 | | | 1,975 | | | 73 | | | 229 | |
|
| | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,217 |
| | 2,136 |
| | 1,821 |
| | 1,189 |
| | 71 |
| | — |
|
| Entergy Louisiana | | 9,099 |
| | 6,603 |
| | 2,136 |
| | 360 |
| | — |
| | — |
|
| Entergy Mississippi | | 3,359 |
| | 2,944 |
| | — |
| | 414 |
| | — |
| | 1 |
|
| Entergy New Orleans | | 492 |
| | 491 |
| | — |
| | — |
| | — |
| | 1 |
|
| Entergy Texas | | 2,331 |
| | 2,065 |
| | — |
| | 266 |
| | — |
| | — |
|
| System Energy | | 1,271 |
| | — |
| | 1,271 |
| | — |
| | — |
| | — |
|
| Total | | 21,769 |
| | 14,239 |
| | 5,228 |
| | 2,229 |
| | 71 |
| | 2 |
|
(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.
| |
(a) | “Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,53321,775 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, environmental regulations,Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 6,8007,963 MW of new long-term resources and the deactivation of over 5,200about 4,241 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 timetime-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 longer-termlong-term requirements through a broad range of wholesale power
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products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Louisiana’s June 2005Texas’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. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the 718APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW gas-fired Perryville plant,to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of which 35%an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the outputWalnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is soldcompleted and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
•In September 2020, Entergy Texas;
Entergy Arkansas’s September 2008Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility.APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC’s approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as successoran approved land use and defining corresponding solar regulations. Entergy Louisiana is in interestdiscussions with the counterparty for the St. Jacques facility regarding amendments to Entergy Gulf States Louisiana, owns one-thirdthe agreement to address the impact of the facility;St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar
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facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
•Entergy Arkansas’s November 2012 purchase ofLouisiana expects to start construction on the 62049 MW combined-cycle, gas-fired Hot Spring Energy facility;
Entergy Mississippi’s November 2012 purchase ofSterlington Solar project in the 450 MW, combined-cycle, gas-fired Hinds Energy facility;
Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station.fourth quarter 2024, located in Sterlington, Louisiana. The facility reachedis expected to achieve commercial operation in December 2014;January 2026.
Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine St. Charles generating facility at its existing Little Gypsy electric generating station. Entergy Louisiana received regulatory approval from the LPSC in December 2016 and the facility is scheduled to be in service by mid-2019;
Entergy Texas’s construction of the 993 MW, combined-cycle, gas turbine Montgomery County generating facility at its existing Lewis Creek electric generating station. Entergy Texas received regulatory approval from the PUCT in July 2017 and the facility is scheduled to be in service by mid-2021; and
Entergy Louisiana’s construction of the 994 MW, combined-cycle, gas turbine Lake Charles generating facility at its existing Nelson electric generating station. Entergy Louisiana received regulatory approval from the LPSC in July 2017 and the facility is scheduled to be in service by mid-2020.
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 BendBend’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 ArkansasArkansas’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 December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;
In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
•In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC 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 peta 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 and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’sa 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 withand TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, executed a 10-year agreement 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 has approved the project and the expected commercial operation date isdeliveries pursuant to that agreement commenced in June 2019;2018;
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•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction has received regulatory approvalIn November 2019, LS Power sold and will begin in June 2022;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 has received regulatory approval and will beginbegan in June 2018; and
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
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•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 Chicot County, Arkansas. Entergy Arkansas filed forLivingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
•In October 2017.2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
•In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
•In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC
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requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
•In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, 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 as early as June 2026.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.
In June 2016,2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for long-term renewable generationsolar photovoltaic and wind resources. The RFP was seeking up to 200 MWEntergy Louisiana selected a combination of renewablePPA and build own transfer resources that could provide energy, fuel diversity,in March 2023 some of which have been executed and other benefits to customers. Two proposals were placedare noted above, and negotiation of definitive agreements for the remaining resources are in the primary selection list and the transactions are currently in negotiations.progress.
In July 2016,October 2022, Entergy Services, on behalf of Entergy New Orleans,Texas, issued an RFP for long-term renewable generation resources. The RFP was seeking up to 20 MW of renewable resources that could provide increased depth and diversity to Entergy New Orleans’s generation resource portfolio. In May 2017, Entergy New Orleans selected three proposals, including a 5 MW self-build option for an aggregated solar photovoltaic resource located within Orleans Parish, Louisiana. and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.
In October 2017,November 2022, Entergy New Orleans filedServices, on behalf of Entergy Mississippi, issued an application seeking City Council approvalRFP for the self-build option, which is pending before the City Council. Following unsuccessful negotiations related to the other proposalssolar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2017, Entergy New Orleans suspended negotiations in November 20172023, and invited bidders to re-submit proposals with current information. From these submissions, in January 2018, Entergy New Orleans selected three proposals with an anticipated total capacitynegotiation of 90 MW. The updated proposals selecteddefinitive agreements are in addition to the self-build option.progress for all resources.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’samong others:
•In 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; and2016, 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). The Utility operating companies have also entered into various limited-facility is located near El Dorado, Arkansas and long-term contractshas been in recent years as a resultoperation since July 2003;
•In October 2019, Entergy Mississippi’s acquisition of bilateral negotiations.the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The facility is located in Choctaw County and has been in operation since July 2003;
The•In November 2020, Entergy Louisiana’s acquisition of the Washington Parish Energy Center is a 361 MW natural gas-fired peaking power plant under advanced development approximately 60 miles north of New Orleans on a partially developed site Calpine has owned since 2001. This simple-cycle power plant is proposed to be developed pursuant to an agreement with Entergy Louisiana which will purchasepurchased from Calpine in 2019. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
•In June 2021, Entergy Texas’s acquisition of 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. The facility has been in operation since January 2010; and
•In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a fixed paymentto-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC voted to reimburse construction costs plusapprove this project and in September 2023, Entergy Louisiana reported
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to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated premium. rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.
In May 2017,December 2020, Entergy LouisianaTexas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. A procedural schedule has not yet been set.
In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas’s proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas’s rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC’s order.
In July 2021, Entergy Louisiana filed with the LPSC seeking certificationan application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the plant.settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The application is pending.settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected by ato the transmission system operatingwhich operates at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilitiessteam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined-cycle combustion turbine generators and reciprocating internal combustion engine generators that are provided dispatch instructionsfueled by MISO.natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that participate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include generating and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of the SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving, the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states.SERC serves as a regional entityRegional 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 the SERC Region.16 central and southeastern states.
Natural Gas Property
As of December 31, 2017,Entergy Louisiana and Entergy New Orleans distributed and transportedalso distribute natural gas for distribution within New Orleans, Louisiana, through approximately 2,500 miles of gas pipeline. As of December 31, 2017, the gas properties of Entergy Louisiana, which are locatedto retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.
Other Revenues
Entergy’s revenues from its non-utility operations include the sale of electric power and capacity to wholesale customers, day-ahead sales of energy in a market administered by an ISO, operation and management services fees, and amortization of a below-market PPA. In 2022 and 2021, the majority of revenues were from the Palisades nuclear power plant located in Michigan, which was shut down in May 2022 and subsequently sold in June 2022. Almost all of the Palisades nuclear plant output was sold under a 15-year PPA with Consumers Energy, which was executed as part of the acquisition of the plant in 2007 and expired in April 2022. Prices under the original PPA ranged from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA was $51/MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022 at a price of $24.14/MWh. Entergy issued monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortized a liability to revenue over the life of the agreement. The amount amortized each period was based upon the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $5 million in 2022 and $12 million in 2021. See Note 14 to the financial statements for discussion of the sale of the Palisades plant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Practical Expedients and Exceptions
Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.
Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some Entergy subsidiaries in the non-utility operations business have services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy Louisiana’s financial position.revenues.
TitleRecovery of Fuel Costs
TheEntergy’s Utility operating companies’ generating stationsrate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are generally locatedbilled to customers. Where the fuel component of revenues is based on properties owneda pre-determined fuel cost (fixed fuel factor), the fuel factor remains in fee simple. Mosteffect until changed as part of the substations and transmission and distribution linesa general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are constructed on private property or public rights-of-way pursuantintended 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 byrecover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. The following tables set forth a reconciliation of changes in the allowance for doubtful accounts for the years ended December 31, 2023 and 2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy
Arkansas | | Entergy
Louisiana | | Entergy
Mississippi | | Entergy
New
Orleans | | Entergy
Texas |
| | (In Millions) |
| Balance as of December 31, 2022 | $30.9 | | | $6.5 | | | $7.6 | | | $2.5 | | | $11.9 | | | $2.4 | |
| Provisions | 38.7 | | | 9.4 | | | 13.9 | | | 7.3 | | | 3.4 | | | 4.7 | |
| Write-offs | (83.1) | | | (20.6) | | | (31.3) | | | (10.4) | | | (10.7) | | | (10.1) | |
| Recoveries | 39.4 | | | 11.9 | | | 15.9 | | | 3.9 | | | 3.2 | | | 4.5 | |
| Balance as of December 31, 2023 | $25.9 | | | $7.2 | | | $6.1 | | | $3.3 | | | $7.8 | | | $1.5 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy
Arkansas | | Entergy
Louisiana | | Entergy
Mississippi | | Entergy
New
Orleans | | Entergy
Texas |
| | (In Millions) |
| Balance as of December 31, 2021 | $68.6 | | | $13.1 | | | $29.2 | | | $7.2 | | | $13.3 | | | $5.8 | |
| Provisions (a) | 40.6 | | | 14.9 | | | 10.7 | | | 3.2 | | | 7.7 | | | 4.1 | |
| Write-offs | (112.5) | | | (31.2) | | | (45.1) | | | (12.1) | | | (13.5) | | | (10.6) | |
| Recoveries | 34.2 | | | 9.7 | | | 12.8 | | | 4.2 | | | 4.4 | | | 3.1 | |
| Balance as of December 31, 2022 | $30.9 | | | $6.5 | | | $7.6 | | | $2.5 | | | $11.9 | | | $2.4 | |
(a)Provisions include estimated incremental bad debt expenses, and revisions to those estimates, resulting from the COVID-19 pandemic of ($6.4) million for Entergy, $6.4 million for Entergy Arkansas, ($8.5) million for Entergy Louisiana, ($3.0) million for Entergy New Orleans, and ($1.3) million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for information on regulatory assets recorded as a result of the COVID-19 pandemic and orders issued by retail regulators.
The allowance is calculated as the historical rate of customer write-offs multiplied by the current accounts receivable balance, taking into account the length of time the receivable balances have been outstanding. The rate of customer write-offs has historically experienced minimal variation, although general economic conditions, such as the COVID-19 pandemic or other economic hardships, can affect the rate of customer write-offs. Management monitors the current condition of individual customer accounts to manage collections and ensure bad debt expense is recorded in a timely manner.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 Part I, Item 1A of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The terms and conditions of service, including electric and gas rates, of the Registrant Subsidiaries are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation, and uncertainty as to ultimate results.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation, or experience risks associated with participation in the MISO markets and allocation of transmission upgrade costs.
•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.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material effects on Entergy and its Utility operating companies affected by severe weather.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the liensUtility operating companies’ results of mortgages securing bonds issued by those companies. operations.
Nuclear Operating, Shutdown, and Regulatory Risks
•The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiaryresults of operations, financial condition, and liquidity of Entergy Texas,Arkansas, Entergy Louisiana, and System Energy could be materially affected by the following:
◦inability to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last materially longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums and/or assessments imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets 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.
Business Risks
•Entergy and the Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints. Disruptions in the capital and credit markets or a downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could, among other things, adversely affect their ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.
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Entergy Corporation, Utility operating companies, and System Energy
•The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals or commitments, among other potential causes.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions, is not 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 mortgage lien. Lewis Creek is leased tosubsidiaries’ results of operations.
•Entergy and operated by Entergy Texas.
Fuel Supply
The sources of generation and average fuel cost per kWh forits subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Entergy could be negatively affected by the effects of climate change, including physical risks, such as increased frequency and intensity of hurricanes, availability of water, droughts, and other severe weather and wildfires, and transition risks, such as environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, or increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding of such benefit plans and result in increased benefit plan costs.
•The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ physical infrastructure or technology systems may adversely affect Entergy’s business and results of operations.
•Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
•Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy’s results of operations, financial condition, and liquidity.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the years 2015-2017 were:affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds, which financing may not be available on terms acceptable to System Energy when required.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
•The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
| 2017 | | 38 | | 2.60 |
| | 26 | | 0.86 |
| | 8 | | 2.35 |
| | 8 | | 4.02 |
| | 20 | | 3.09 |
|
| 2016 | | 41 | | 2.44 |
| | 28 | | 0.63 |
| | 7 | | 2.65 |
| | 9 | | 3.71 |
| | 15 | | 3.13 |
|
| 2015 | | 35 | | 2.65 |
| | 31 | | 0.85 |
| | 7 | | 2.85 |
| | 11 | | 3.63 |
| | 16 | | 3.24 |
|
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Actual 2017
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 24,000 MW of electric generating capacity. Entergy delivers electricity to approximately 3 million Utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $12.1 billion in 2023 and had approximately 12,000 employees as of December 31, 2023.
Entergy operates primarily through a single reportable segment, Utility. The Utility 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 in portions of Louisiana. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022 and upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable segment. See Note 13 to the financial statements for discussion of and financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow its utility business through a customer-centric approach designed to understand and meet customer needs, creating value for all of its key stakeholders, including customers, communities, employees, and owners. As part of its strategy, Entergy invests significant capital to support customer growth and its customers’ growing demands for greater reliability, resilience, and clean energy, while remaining focused on affordability. Entergy manages risks by ensuring its Utility investments are customer-driven, the result of robust analysis, supported by broad stakeholder outreach and progressive regulatory constructs, and executed with disciplined project management. Further, Entergy continues to integrate key sustainability elements, including social responsibility and good governance, into every decision it makes.
Utility
The Utility 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. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The Utility has a diverse power generation portfolio, including increasingly carbon-free energy sources, which is consistent with Entergy’s strong support for the environment.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Customers
As of December 31, 2023, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 730 | | | 24 | | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,105 | | | 37 | | | 96 | | | 47 | |
| Entergy Mississippi | Portions of Mississippi | | 459 | | | 15 | | | | | |
| Entergy New Orleans | City of New Orleans | | 208 | | | 7 | | | 108 | | | 53 | |
| Entergy Texas | Portions of Texas | | 512 | | | 17 | | | | | |
| Total | | | 3,014 | | | 100 | | | 204 | | | 100 | |
Electric and Natural Gas Energy Sales
Electric Energy Sales
The total electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 23, 2023, Entergy reached a 2023 peak demand of 23,319 MWh, compared to the 2022 peak of 22,301 MWh recorded on June 24, 2022. Selected electric energy sales data for 2023 is shown in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (GWh) |
| Sales to retail customers | 22,481 | | | 57,681 | | | 12,854 | | | 5,696 | | | 21,146 | | | — | | | 119,858 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 2,218 | | | 4,406 | | | — | | | — | | | — | | | 10,574 | | | — | |
| Others | 5,777 | | | 1,534 | | | 4,598 | | | 2,818 | | | 462 | | | — | | | 15,189 | |
| Total | 30,476 | | | 63,621 | | | 17,452 | | | 8,514 | | | 21,608 | | | 10,574 | | | 135,047 | |
| Average use per residential customer (kWh) | 12,561 | | | 14,893 | | | 14,226 | | | 12,610 | | | 14,941 | | | — | | | 14,089 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2023 combined electric sales volume as a percentage of total electric sales volume, and 2023 combined electric revenues as a percentage of total 2023 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 26.9 | | 38.4 |
| Commercial | | 20.9 | | 25.3 |
| Industrial (a) | | 39.1 | | 26.8 |
| Governmental | | 1.8 | | 2.3 |
| Wholesale/Other | | 11.3 | | 7.2 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Natural Gas Energy Sales
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 8,917,149 and 6,130,048 Mcf, respectively, of natural gas to retail customers in 2023. In 2023, 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 2023.
Following is data concerning Entergy New Orleans’s 2023 retail operating revenue sources:
| | | | | | | | | | | | | | |
| Customer Class | | % of Electric Operating Revenue | | % of Natural Gas Operating Revenue |
| Residential | | 48 | | 51 |
| Commercial | | 35 | | 26 |
| Industrial | | 5 | | 17 |
| Governmental/Municipal | | 12 | | 6 |
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 and System Energy’s 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 | | $10.1 (a) | | 9.15% - 10.15% | | 5.62% | | 38.7% (b) | | - forward test year formula rate plan - riders: fuel and purchased power, MISO, capacity, Grand Gulf, energy efficiency |
| Entergy Louisiana (electric) | | $15.7 (c) | | 9.0% - 10.0% | | 6.66% | | 49.51% | | - formula rate plan through 2022 test year - riders/specific recovery: MISO, capacity, transmission, fuel, distribution, tax reform |
| Entergy Louisiana (gas) | | $0.15 (d) | | 9.3% - 10.3% | | 6.93% | | 51.83% | | - gas rate stabilization plan - rider: gas infrastructure |
| Entergy Mississippi | | $4.2 (e) | | 9.74% - 11.88% | | 7.06% | | 46.76% | | - formula rate plan with forward-looking features - riders: fuel, Grand Gulf, MISO, unit power cost, storm damage, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit, power management |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy New Orleans (electric) | | $1.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity costs |
| Entergy New Orleans (gas) | | $0.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - rider: purchased gas |
| Entergy Texas | | $4.4 (h) | | 9.57% | | 6.61% | | 51.2% | | - rate case and cost recovery riders - riders: fuel, capacity, cost recovery riders (distribution, transmission, and generation), rate case expenses, advanced metering infrastructure surcharge, and tax reform, among others |
| System Energy | | $1.74 (i) | | 10.94% (j) | | 8.54% | | 59.5% (j) | | - monthly cost of service |
(a)Based on 2024 test year.
(b)Based on $1.9 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted-average cost of capital calculation.
(c)Based on December 31, 2022 test year and excludes approximately $300 million of transmission plant investment included in the transmission recovery mechanism and approximately $200 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of net accumulated deferred tax liability items included in the tax reform adjustment mechanism.
(d)Based on September 30, 2022 test year.
(e)Based on 2023 forward test year.
(f)Based on December 31, 2022 test year and known and measurables through December 31, 2023.
(g)In October 2023 the City Council approved a three-year extension of Entergy New Orleans’s formula rate plan, modified to reflect a 55% fixed capital structure for rate setting purposes.
(h)Based on December 31, 2021 test year.
(i)Based on calculation as of December 31, 2023.
(j)Effective July 2022, Entergy Mississippi’s bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, and a rate base reduction for the advance collection of sale-leaseback rental costs. See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
Entergy Arkansas
Formula Rate Plan
Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change 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
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2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. As part of the settlement of the 2023 formula rate plan proceeding, Entergy Arkansas agreed to file its next base rate case no later than February 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.
Other
In June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing for a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The APSC approved an initial offering of 100 MW of solar capacity to be made available under this tariff.
In June 2023 the APSC approved Entergy Arkansas’s Go ZERO tariff, which provides participating industrial and commercial customers the opportunity to chose from a number of clean energy options to help them achieve their sustainability goals.
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. In 2021 the LPSC approved a settlement extending the formula rate plan for test years 2020, 2021 and 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and certain distribution investments, among other items. In August
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2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years, test years 2023-2025, which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study, with a 2024-2026 test year formula rate plan. The application complies with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service/rate case. See Note 2 to the financial statements for a discussion of Entergy Louisiana’s application.
Fuel and Purchased Power Cost 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, sourcesEntergy Louisiana filed an application with the LPSC to suspend these seasonal hedging programs and implement financial hedges with terms up to five years for a portion of its natural gas exposure, which was approved in November 2018.
Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
Retail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension
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allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then-current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the
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return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider.
In 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.
In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the annual power management and grid modernization riders effective January 2023.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
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Other
In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule.
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. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.
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.
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 filings to recover storm-related costs.
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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 and Purchased Power Cost 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. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 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. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.
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 to be recovered through a purchased power capacity rider. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs. In 2023, the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through a purchased power capacity rider.
Transmission, Distribution, and Generation 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 permitted 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. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their
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distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Other
In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.
As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.
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
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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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric
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service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2024-2058.
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, 2023 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,036 | | | 1,548 | | | 521 | | | 1,825 | | | 969 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,798 | | | 5,594 | | | 2,728 | | | 2,137 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,904 | | | 1,744 | | | 641 | | | — | | | 417 | | | — | | | 102 | |
| Entergy New Orleans | | 662 | | | 635 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,234 | | | 990 | | | 1,994 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,245 | | | — | | | — | | | 1,245 | | | — | | | — | | | — | |
| Total | | 23,879 | | | 10,511 | | | 5,884 | | | 5,207 | | | 1,975 | | | 73 | | | 229 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,775 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 7,963 MW of new long-term resources and the deactivation of about 4,241 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
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products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•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. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC’s approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the St. Jacques facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar
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facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
•Entergy Louisiana expects to start construction on the 49 MW Sterlington Solar project in the fourth quarter 2024, located in Sterlington, Louisiana. The facility is expected to achieve commercial operation in January 2026.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power purchasesagreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from affiliates under lifea 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 and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a 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 and TX LFG Energy, LP, a wholly-owned subsidiary of unitMontauk Energy Holdings, LLC, executed a 10-year agreement 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 agreements, includingagreement;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Unit Power Sales Agreement, are:Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
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|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 | | 2018 |
| Entergy Arkansas (a) | 28 | % | | 33 | % | | 49 | % | | 51 | % | | 18 | % | | 15 | % | | — | % | | 1 | % | | 5 | % | | — |
| Entergy Louisiana | 38 | % | | 49 | % | | 26 | % | | 33 | % | | 3 | % | | 4 | % | | 9 | % | | 14 | % | | 24 | % | | — |
| Entergy Mississippi (b) | 47 | % | | 55 | % | | 18 | % | | 30 | % | | 13 | % | | 15 | % | | — | % | | — |
| | 22 | % | | — |
| Entergy New Orleans (b) | 53 | % | | 57 | % | | 33 | % | | 41 | % | | 2 | % | | 1 | % | | — | % | | 1 | % | | 12 | % | | — |
| Entergy Texas | 30 | % | | 33 | % | | 10 | % | | 17 | % | | 7 | % | | 9 | % | | 28 | % | | 41 | % | | 25 | % | | — |
| System Energy (c) | — |
| | — |
| | 100 | % | | 100 | % | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Utility (a) (b) | 38 | % | | 44 | % | | 26 | % | | 36 | % | | 8 | % | | 9 | % | | 8 | % | | 11 | % | | 20 | % | | — |
| |
(a) | Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2017 and is expected to provide about less than1% of its generation in 2018. |
| |
(b) | Solar power provided less than 1% of Entergy Mississippi’s and Entergy New Orleans's generation in 2017 and is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2018. |
| |
(c) | Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. |
| |
(d) | Excludes MISO purchases |
| |
(e) | In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. MISO purchases cannot be projected for 2018. |
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
Some•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the Utility’sSt. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
•In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
•In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC
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Entergy Corporation, Utility operating companies, and System Energy
requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
•In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, 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 as early as June 2026.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. Entergy Louisiana selected a combination of PPA and build own transfer resources in March 2023 some of which have been executed and are noted above, and negotiation of definitive agreements for the remaining resources are in progress.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2023, and negotiation of definitive agreements are in progress for all resources.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including among others:
•In March 2016, Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) acquisitions of the 1,980 MW (summer rating), natural gas-fired, plantscombined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating). The facility is located near El Dorado, Arkansas and has been in operation since July 2003;
•In October 2019, Entergy Mississippi’s acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The facility is located in Choctaw County and has been in operation since July 2003;
•In November 2020, Entergy Louisiana’s acquisition of 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. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
•In June 2021, Entergy Texas’s acquisition of 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. The facility has been in operation since January 2010; and
•In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC voted to approve this project and in September 2023, Entergy Louisiana reported
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Entergy Corporation, Utility operating companies, and System Energy
to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. A procedural schedule has not yet been set.
In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas’s proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A
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paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas’s rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC’s order.
In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are also capableinterconnected to the transmission system which operates at various voltages up to 500 kV. These generating units consist of using fuel oil, if necessary. Although based on current economicssteam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined-cycle combustion turbine generators and reciprocating internal combustion engine generators that are fueled by natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that participate in the MISO wholesale electric market. Additionally, some of the Utility does not expect fuel oil useoperating companies also offer customer services and products that include generating and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in 2018, itthe wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is possible that various operational events including weatheran essential link in the safe, cost-effective delivery of electric power across all or pipeline maintenance may requireparts of 15 U.S. states and the useCanadian province of fuel oil.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.
Natural Gas
Entergy Louisiana and Entergy New Orleans also distribute natural gas to retail customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Gas transferred to customers is measured by a meter at the customer’s property. Entergy issues monthly invoices to customers at rates approved by regulators for the volume of gas transferred to date.
Other Revenues
Entergy’s revenues from its non-utility operations include the sale of electric power and capacity to wholesale customers, day-ahead sales of energy in a market administered by an ISO, operation and management services fees, and amortization of a below-market PPA. In 2022 and 2021, the majority of revenues were from the Palisades nuclear power plant located in Michigan, which was shut down in May 2022 and subsequently sold in June 2022. Almost all of the Palisades nuclear plant output was sold under a 15-year PPA with Consumers Energy, which was executed as part of the acquisition of the plant in 2007 and expired in April 2022. Prices under the original PPA ranged from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA was $51/MWh. Entergy executed an additional PPA to cover the period from the expiration of the original PPA through final shutdown in May 2022 at a price of $24.14/MWh. Entergy issued monthly invoices to Consumers Energy for electric sales based on the actual output of electricity and related services provided during the previous month at the contract price. The PPA was at below-market prices at the time of the acquisition and Entergy amortized a liability to revenue over the life of the agreement. The amount amortized each period was based upon the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $5 million in 2022 and $12 million in 2021. See Note 14 to the financial statements for discussion of the sale of the Palisades plant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Practical Expedients and Exceptions
Entergy has elected not to disclose the value of unsatisfied performance obligations for contracts with an original expected term of one year or less, or for revenue recognized in an amount equal to what Entergy has the right to bill the customer for services performed.
Most of Entergy’s contracts, except in a few cases where there are defined minimums or stated terms, are on demand. This results in customer bills that vary each month based on an approved tariff and usage. Entergy imposes monthly or annual minimum requirements on some customers primarily as credit and cost recovery guarantees and not as pricing for unsatisfied performance obligations. These minimums typically expire after the initial term or when specified costs have been recovered. The minimum amounts are part of each month’s bill and recognized as revenue accordingly. Some Entergy subsidiaries in the non-utility operations business have services contracts that have fixed components and terms longer than one year. The total fixed consideration related to these unsatisfied performance obligations, however, is not material to Entergy revenues.
Recovery of Fuel Costs
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are based on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of expected losses on its accounts receivable balances. Due to the essential nature of utility services, Entergy has historically experienced a low rate of default on its accounts receivables. The following tables set forth a reconciliation of changes in the allowance for doubtful accounts for the years ended December 31, 2023 and 2022.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy
Arkansas | | Entergy
Louisiana | | Entergy
Mississippi | | Entergy
New
Orleans | | Entergy
Texas |
| | (In Millions) |
| Balance as of December 31, 2022 | $30.9 | | | $6.5 | | | $7.6 | | | $2.5 | | | $11.9 | | | $2.4 | |
| Provisions | 38.7 | | | 9.4 | | | 13.9 | | | 7.3 | | | 3.4 | | | 4.7 | |
| Write-offs | (83.1) | | | (20.6) | | | (31.3) | | | (10.4) | | | (10.7) | | | (10.1) | |
| Recoveries | 39.4 | | | 11.9 | | | 15.9 | | | 3.9 | | | 3.2 | | | 4.5 | |
| Balance as of December 31, 2023 | $25.9 | | | $7.2 | | | $6.1 | | | $3.3 | | | $7.8 | | | $1.5 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy | | Entergy
Arkansas | | Entergy
Louisiana | | Entergy
Mississippi | | Entergy
New
Orleans | | Entergy
Texas |
| | (In Millions) |
| Balance as of December 31, 2021 | $68.6 | | | $13.1 | | | $29.2 | | | $7.2 | | | $13.3 | | | $5.8 | |
| Provisions (a) | 40.6 | | | 14.9 | | | 10.7 | | | 3.2 | | | 7.7 | | | 4.1 | |
| Write-offs | (112.5) | | | (31.2) | | | (45.1) | | | (12.1) | | | (13.5) | | | (10.6) | |
| Recoveries | 34.2 | | | 9.7 | | | 12.8 | | | 4.2 | | | 4.4 | | | 3.1 | |
| Balance as of December 31, 2022 | $30.9 | | | $6.5 | | | $7.6 | | | $2.5 | | | $11.9 | | | $2.4 | |
(a)Provisions include estimated incremental bad debt expenses, and revisions to those estimates, resulting from the COVID-19 pandemic of ($6.4) million for Entergy, $6.4 million for Entergy Arkansas, ($8.5) million for Entergy Louisiana, ($3.0) million for Entergy New Orleans, and ($1.3) million for Entergy Texas that have been deferred as regulatory assets. See Note 2 to the financial statements for information on regulatory assets recorded as a result of the COVID-19 pandemic and orders issued by retail regulators.
The allowance is calculated as the historical rate of customer write-offs multiplied by the current accounts receivable balance, taking into account the length of time the receivable balances have been outstanding. The rate of customer write-offs has historically experienced minimal variation, although general economic conditions, such as the COVID-19 pandemic or other economic hardships, can affect the rate of customer write-offs. Management monitors the current condition of individual customer accounts to manage collections and ensure bad debt expense is recorded in a timely manner.
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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 Part I, Item 1A of this report, “Risk Factors,” before deciding whether to invest in Entergy or the Registrant Subsidiaries.
Utility Regulatory Risks
•The terms and conditions of service, including electric and gas rates, of the Registrant Subsidiaries are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation, and uncertainty as to ultimate results.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation, or experience risks associated with participation in the MISO markets and allocation of transmission upgrade costs.
•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.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material effects on Entergy and its Utility operating companies affected by severe weather.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, and System Energy could be materially affected by the following:
◦inability to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last materially longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums and/or assessments imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets 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.
Business Risks
•Entergy and the Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints. Disruptions in the capital and credit markets or a downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could, among other things, adversely affect their ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.
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•The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals or commitments, among other potential causes.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Entergy could be negatively affected by the effects of climate change, including physical risks, such as increased frequency and intensity of hurricanes, availability of water, droughts, and other severe weather and wildfires, and transition risks, such as environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, or increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding of such benefit plans and result in increased benefit plan costs.
•The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ physical infrastructure or technology systems may adversely affect Entergy’s business and results of operations.
•Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
•Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy’s results of operations, financial condition, and liquidity.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds, which financing may not be available on terms acceptable to System Energy when required.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
•The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.
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Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 24,000 MW of electric generating capacity. Entergy delivers electricity to approximately 3 million Utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $12.1 billion in 2023 and had approximately 12,000 employees as of December 31, 2023.
Entergy operates primarily through a single reportable segment, Utility. The Utility 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 in portions of Louisiana. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022 and upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable segment. See Note 13 to the financial statements for discussion of and financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow its utility business through a customer-centric approach designed to understand and meet customer needs, creating value for all of its key stakeholders, including customers, communities, employees, and owners. As part of its strategy, Entergy invests significant capital to support customer growth and its customers’ growing demands for greater reliability, resilience, and clean energy, while remaining focused on affordability. Entergy manages risks by ensuring its Utility investments are customer-driven, the result of robust analysis, supported by broad stakeholder outreach and progressive regulatory constructs, and executed with disciplined project management. Further, Entergy continues to integrate key sustainability elements, including social responsibility and good governance, into every decision it makes.
Utility
The Utility 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. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The Utility has a diverse power generation portfolio, including increasingly carbon-free energy sources, which is consistent with Entergy’s strong support for the environment.
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Customers
As of December 31, 2023, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
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| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 730 | | | 24 | | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,105 | | | 37 | | | 96 | | | 47 | |
| Entergy Mississippi | Portions of Mississippi | | 459 | | | 15 | | | | | |
| Entergy New Orleans | City of New Orleans | | 208 | | | 7 | | | 108 | | | 53 | |
| Entergy Texas | Portions of Texas | | 512 | | | 17 | | | | | |
| Total | | | 3,014 | | | 100 | | | 204 | | | 100 | |
Electric and Natural Gas Energy Sales
Electric Energy Sales
The total electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 23, 2023, Entergy reached a 2023 peak demand of 23,319 MWh, compared to the 2022 peak of 22,301 MWh recorded on June 24, 2022. Selected electric energy sales data for 2023 is shown in the table below:
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| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (GWh) |
| Sales to retail customers | 22,481 | | | 57,681 | | | 12,854 | | | 5,696 | | | 21,146 | | | — | | | 119,858 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 2,218 | | | 4,406 | | | — | | | — | | | — | | | 10,574 | | | — | |
| Others | 5,777 | | | 1,534 | | | 4,598 | | | 2,818 | | | 462 | | | — | | | 15,189 | |
| Total | 30,476 | | | 63,621 | | | 17,452 | | | 8,514 | | | 21,608 | | | 10,574 | | | 135,047 | |
| Average use per residential customer (kWh) | 12,561 | | | 14,893 | | | 14,226 | | | 12,610 | | | 14,941 | | | — | | | 14,089 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2023 combined electric sales volume as a percentage of total electric sales volume, and 2023 combined electric revenues as a percentage of total 2023 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 26.9 | | 38.4 |
| Commercial | | 20.9 | | 25.3 |
| Industrial (a) | | 39.1 | | 26.8 |
| Governmental | | 1.8 | | 2.3 |
| Wholesale/Other | | 11.3 | | 7.2 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
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Entergy Corporation, Utility operating companies, and System Energy
Natural Gas Energy Sales
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 8,917,149 and 6,130,048 Mcf, respectively, of natural gas to retail customers in 2023. In 2023, 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 2023.
Following is data concerning Entergy New Orleans’s 2023 retail operating revenue sources:
| | | | | | | | | | | | | | |
| Customer Class | | % of Electric Operating Revenue | | % of Natural Gas Operating Revenue |
| Residential | | 48 | | 51 |
| Commercial | | 35 | | 26 |
| Industrial | | 5 | | 17 |
| Governmental/Municipal | | 12 | | 6 |
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 and System Energy’s retail rate mechanisms are discussed below.
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| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy Arkansas | | $10.1 (a) | | 9.15% - 10.15% | | 5.62% | | 38.7% (b) | | - forward test year formula rate plan - riders: fuel and purchased power, MISO, capacity, Grand Gulf, energy efficiency |
| Entergy Louisiana (electric) | | $15.7 (c) | | 9.0% - 10.0% | | 6.66% | | 49.51% | | - formula rate plan through 2022 test year - riders/specific recovery: MISO, capacity, transmission, fuel, distribution, tax reform |
| Entergy Louisiana (gas) | | $0.15 (d) | | 9.3% - 10.3% | | 6.93% | | 51.83% | | - gas rate stabilization plan - rider: gas infrastructure |
| Entergy Mississippi | | $4.2 (e) | | 9.74% - 11.88% | | 7.06% | | 46.76% | | - formula rate plan with forward-looking features - riders: fuel, Grand Gulf, MISO, unit power cost, storm damage, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit, power management |
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| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy New Orleans (electric) | | $1.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity costs |
| Entergy New Orleans (gas) | | $0.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - rider: purchased gas |
| Entergy Texas | | $4.4 (h) | | 9.57% | | 6.61% | | 51.2% | | - rate case and cost recovery riders - riders: fuel, capacity, cost recovery riders (distribution, transmission, and generation), rate case expenses, advanced metering infrastructure surcharge, and tax reform, among others |
| System Energy | | $1.74 (i) | | 10.94% (j) | | 8.54% | | 59.5% (j) | | - monthly cost of service |
(a)Based on 2024 test year.
(b)Based on $1.9 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted-average cost of capital calculation.
(c)Based on December 31, 2022 test year and excludes approximately $300 million of transmission plant investment included in the transmission recovery mechanism and approximately $200 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of net accumulated deferred tax liability items included in the tax reform adjustment mechanism.
(d)Based on September 30, 2022 test year.
(e)Based on 2023 forward test year.
(f)Based on December 31, 2022 test year and known and measurables through December 31, 2023.
(g)In October 2023 the City Council approved a three-year extension of Entergy New Orleans’s formula rate plan, modified to reflect a 55% fixed capital structure for rate setting purposes.
(h)Based on December 31, 2021 test year.
(i)Based on calculation as of December 31, 2023.
(j)Effective July 2022, Entergy Mississippi’s bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, and a rate base reduction for the advance collection of sale-leaseback rental costs. See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
Entergy Arkansas
Formula Rate Plan
Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change 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
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2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. As part of the settlement of the 2023 formula rate plan proceeding, Entergy Arkansas agreed to file its next base rate case no later than February 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.
Other
In June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing for a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The APSC approved an initial offering of 100 MW of solar capacity to be made available under this tariff.
In June 2023 the APSC approved Entergy Arkansas’s Go ZERO tariff, which provides participating industrial and commercial customers the opportunity to chose from a number of clean energy options to help them achieve their sustainability goals.
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. In 2021 the LPSC approved a settlement extending the formula rate plan for test years 2020, 2021 and 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and certain distribution investments, among other items. In August
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2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years, test years 2023-2025, which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study, with a 2024-2026 test year formula rate plan. The application complies with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service/rate case. See Note 2 to the financial statements for a discussion of Entergy Louisiana’s application.
Fuel and Purchased Power Cost 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. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension
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allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then-current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the
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return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider.
In 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.
In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the annual power management and grid modernization riders effective January 2023.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
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Other
In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule.
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. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.
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.
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 filings to recover storm-related costs.
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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 and Purchased Power Cost 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. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 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. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.
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 to be recovered through a purchased power capacity rider. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs. In 2023, the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through a purchased power capacity rider.
Transmission, Distribution, and Generation 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 permitted 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. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their
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distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Other
In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.
As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.
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
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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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric
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service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2024-2058.
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, 2023 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,036 | | | 1,548 | | | 521 | | | 1,825 | | | 969 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,798 | | | 5,594 | | | 2,728 | | | 2,137 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,904 | | | 1,744 | | | 641 | | | — | | | 417 | | | — | | | 102 | |
| Entergy New Orleans | | 662 | | | 635 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,234 | | | 990 | | | 1,994 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,245 | | | — | | | — | | | 1,245 | | | — | | | — | | | — | |
| Total | | 23,879 | | | 10,511 | | | 5,884 | | | 5,207 | | | 1,975 | | | 73 | | | 229 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,775 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 7,963 MW of new long-term resources and the deactivation of about 4,241 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
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products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•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. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC’s approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the St. Jacques facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar
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facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
•Entergy Louisiana expects to start construction on the 49 MW Sterlington Solar project in the fourth quarter 2024, located in Sterlington, Louisiana. The facility is expected to achieve commercial operation in January 2026.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from a 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 and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a 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 and TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, executed a 10-year agreement to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
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•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
•In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
•In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC
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requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
•In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, 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 as early as June 2026.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. Entergy Louisiana selected a combination of PPA and build own transfer resources in March 2023 some of which have been executed and are noted above, and negotiation of definitive agreements for the remaining resources are in progress.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2023, and negotiation of definitive agreements are in progress for all resources.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including among others:
•In March 2016, Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) 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). The facility is located near El Dorado, Arkansas and has been in operation since July 2003;
•In October 2019, Entergy Mississippi’s acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The facility is located in Choctaw County and has been in operation since July 2003;
•In November 2020, Entergy Louisiana’s acquisition of 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. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
•In June 2021, Entergy Texas’s acquisition of 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. The facility has been in operation since January 2010; and
•In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC voted to approve this project and in September 2023, Entergy Louisiana reported
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to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. A procedural schedule has not yet been set.
In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas’s proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A
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paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas’s rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC’s order.
In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to the transmission system which operates at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined-cycle combustion turbine generators and reciprocating internal combustion engine generators that are fueled by natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that participate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include generating and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2023, 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, 2023, 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
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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 average fuel cost per kWh for the Utility operating companies and System Energy for the years 2021-2023 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2023 | | (Cents Per kWh) |
| Entergy Arkansas | | 1.98 | | | 0.50 | | | 3.09 | | | 1.98 | | | 11.57 | | | 0.77 | |
| Entergy Louisiana | | 2.34 | | | 0.60 | | | 3.22 | | | 10.38 | | | 3.76 | | | 2.50 | |
| Entergy Mississippi | | 2.21 | | | — | | | 2.82 | | | 0.03 | | | 5.86 | | | 1.84 | |
| Entergy New Orleans (c) | | 2.05 | | | — | | | — | | | 3.24 | | | — | | | 2.33 | |
| Entergy Texas | | 2.29 | | | — | | | 3.17 | | | 2.25 | | | 5.64 | | | 3.18 | |
| System Energy | | — | | | 0.68 | | | — | | | — | | | — | | | — | |
| Utility | | 2.25 | | | 0.58 | | | 3.06 | | | 6.14 | | | 4.03 | | | 2.61 | |
| | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $0.1 million in 2023, $2.9 million in 2022, and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2023 and projected 2024 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | 1 | % | | 57 | % | | 9 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 47 | % | | 7 | % | | 20 | % | | 2 | % | | 2 | % | | 10 | % | | 12 | % |
| Entergy Mississippi | 63 | % | | 1 | % | | 23 | % | | 7 | % | | 1 | % | | — | % | | 5 | % |
| Entergy New Orleans | 55 | % | | 1 | % | | 36 | % | | 1 | % | | 2 | % | | 1 | % | | 4 | % |
| Entergy Texas | 32 | % | | 25 | % | | 6 | % | | 3 | % | | — | % | | 4 | % | | 30 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 43 | % | | 7 | % | | 27 | % | | 4 | % | | 2 | % | | 5 | % | | 12 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 59 | % | | 12 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 48 | % | | 6 | % | | 30 | % | | 2 | % | | 3 | % | | 11 | % | | — | % |
| Entergy Mississippi | 64 | % | | — | % | | 24 | % | | 10 | % | | 2 | % | | — | % | | — | % |
| Entergy New Orleans | 51 | % | | 1 | % | | 43 | % | | 1 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 43 | % | | 31 | % | | 17 | % | | 6 | % | | 3 | % | | — | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 45 | % | | 6 | % | | 35 | % | | 6 | % | | 3 | % | | 5 | % | | — | % |
(a)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2023 is not projected for 2024.
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 2024, 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%70% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that providesprovide 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 willmay 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 eight one-six two- to three-year and two spot contracts that will supply approximatelyat least 85% of the total coal supply needs in 2018.2024. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of totalIf needed, additional Powder River Basin (PRB) coal requirements will be satisfied bypurchased through contracts with a term of less than one year.year to provide the remaining supply needs. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources, and modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2018.2024. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2018.2024.
Entergy Louisiana has committed to five one-three two- to three-year contracts that will supply approximatelyat least 90% of Nelson Unit 6 coal needs in 2018.2024. 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 forthe Entergy Arkansas’sArkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2018.2024. 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 2018.2024.
For the year 2017, coalCoal transportation delivery rates to Entergy Arkansas-andArkansas- and Entergy Louisiana-operated coal-fired units was adequate forwere able to fully meet supply needs and obligations in 2023. While deliveries remained constrained through summer 2023, improvements were observed in the majoritysecond half of the year but experienced some delaysand are expected to continue in the fourth quarter of 2017. It is expected that delivery times will improve in 2018.2024. Both Entergy Arkansas and Entergy Louisiana control a sufficient number ofenough 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 2018.2024, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units in both the Utility and Entergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2018 or beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdowns of the
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Palisades, Pilgrim, Indian Point 2, and Indian Point 3 plants.2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners.miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with threeone interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with CenterpointSymmetry Energy ServicesSolutions which guaranteesensures Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The CenterpointSymmetry Energy ServiceSolutions gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.
Entergy Louisiana purchased natural gas for resale in 20172023 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
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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. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.
Although the System Agreement has terminated, certain of the Utility operating companies’ 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
OnIn December 19, 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO doesdid 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 owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction), as well as the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff is subject to change and has recently undergone significant changes. As an example, MISO recently has made changes to its capacity accreditation methodology for thermal resources which emphasize performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now pursuing a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources.
MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO’s functional control. This process generally involves parties that wish to interconnect new generation resources submitting to MISO requests to do so, which are then studied and analyzed by MISO, with the participation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO’s current tariff, these requests are studied and considered in clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue.
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.
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
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membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.
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 December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001 the rate proceeding 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
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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 a complaint filed withproceedings at the FERC in January 2017 regardingrelated to System Energy’s return on equity.Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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 retail 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.companies. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate reliefcost recovery with respect to costs associated with Entergy Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. The remainder of Entergy Arkansas’s retained share is sold to Entergy Mississippi through a separate life-of-resource purchase power agreement with Entergy Mississippi. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate reliefcost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy
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Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in
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the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its one outstanding series of first mortgage bonds.bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement to System Energy have ever been required. IfHowever, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement obligations exceed their allocated shares under the Unit Power Sales Agreement. See Note 8 to the financial statements for discussion of the Reallocation Agreement obligations.among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, pursuant to which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans
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assumed all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.
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.
Capital Funds Agreement
System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.
Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such a supplement as security for its one outstanding series of first mortgage bonds. The supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy’s rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital
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contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.
The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement. No such consent would be required to terminate the Capital Funds Agreement or the supplement thereto at this time.
Service Companies
Entergy Services, a corporationlimited 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 servicesas well as to Entergy Wholesale Commodities.Entergy’s non-utility operations business. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations, and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
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
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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
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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. See Note 2 to the financial statements for additional discussion of the business combination.
Entergy New OrleansArkansas Internal Restructuring
In November 2017, pursuant to the agreement in principle,2018, Entergy New Orleans, Inc.Arkansas undertook a multi-step restructuring, including the following:
•Entergy New Orleans,Arkansas, Inc. redeemed its outstanding preferred stock at athe aggregate redemption price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.$32.7 million.
•Entergy New Orleans,Arkansas, Inc. converted from a Louisianaan Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans,Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New OrleansArkansas Power, LLC, a Texas limited liability company (Entergy New OrleansArkansas Power), and Entergy New OrleansArkansas Power assumed substantially all of the liabilities of Entergy New Orleans,Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy New Orleans,Arkansas, Inc. remained in existence and held the membership interests in Entergy New OrleansArkansas Power.
•Entergy New Orleans,Arkansas, Inc. contributed the membership interests in Entergy New OrleansArkansas 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 OrleansArkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017,2018, Entergy New Orleans,Arkansas, Inc. changed its name to Entergy Utility Group,Property, Inc., and Entergy New OrleansArkansas Power then changed its name to Entergy New Orleans,Arkansas, LLC. Entergy New Orleans,Arkansas, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans,Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Earnings Ratios of Registrant Subsidiaries
The Registrant Subsidiaries’ ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:
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| | | | | | | | | |
| | Ratios of Earnings to Fixed Charges Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| Entergy Arkansas | 2.87 | | 3.32 | | 2.04 | | 3.08 | | 3.62 |
| Entergy Louisiana | 3.85 | | 3.57 | | 3.36 | | 3.44 | | 3.30 |
| Entergy Mississippi | 4.49 | | 3.96 | | 3.59 | | 3.23 | | 3.19 |
| Entergy New Orleans | 4.50 | | 4.61 | | 4.90 | | 3.55 | | 1.85 |
| Entergy Texas | 2.41 | | 2.92 | | 2.22 | | 2.39 | | 1.94 |
| System Energy | 4.91 | | 5.39 | | 4.53 | | 4.04 | | 5.66 |
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| | | | | | | | | |
| | Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| Entergy Arkansas | 2.81 | | 3.09 | | 1.85 | | 2.76 | | 3.25 |
| Entergy Louisiana | 3.85 | | 3.57 | | 3.24 | | 3.28 | | 3.14 |
| Entergy Mississippi | 4.36 | | 3.71 | | 3.34 | | 3.00 | | 2.97 |
| Entergy New Orleans | 4.24 | | 4.30 | | 4.50 | | 3.26 | | 1.70 |
The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.
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 plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning services, to nuclear power plants owned by other utilities 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.
On December 29, 2014, Entergy Wholesale Commodities’ Vermont Yankee plant was removed from the grid, after 42 years of operations. The decision to close and decommission Vermont Yankee, which was announced in August 2013, was due to numerous issues including sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the Northeast region. In November 2016, Entergy entered into an agreement to sell 100% of its membership interest in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust fund and the asset retirement obligation for spent fuel management and decommissioning of the plant. Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018 in advance of the planned transaction close. Under the sale and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities, along with partial restoration of the Vermont Yankee site, with the exception of the independent spent fuel storage installation and switchyard, by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. The transaction is contingent upon certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Utility Commission, including approval of site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such assets at closing, is equal to or exceeds $451.95 million, subject to adjustments.
In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of its fuel cycle in January 2017. In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. The transaction was contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy
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refueled the FitzPatrick plant in January and February 2017. The sale closed in March 2017 after obtaining all the necessary approvals.
In October 2015, Entergy determined that it would close the Pilgrim plant. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. The Pilgrim plant is expected to cease operations on May 31, 2019, after refueling in the spring of 2017 and operating through the end of that fuel cycle.
In December 2015, Entergy Wholesale Commodities closed on the sale of its 583 MW Rhode Island State Energy Center, in Johnston, Rhode Island. The base sales price, excluding adjustments, was approximately $490 million. Entergy Wholesale Commodities purchased the Rhode Island State Energy Center for $346 million in December 2011.
In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant on May 31, 2018. Pursuant to the agreement, Consumers Energy would pay Entergy $172 million for the early termination of the PPA. The PPA amendment agreement was subject to regulatory approvals, including approval by the Michigan Public Service Commission. Separately, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017 the Michigan Public Service Commission issued an order conditionally approving the PPA amendment transaction, but granting Consumers Energy recovery of only $136.6 million of the $172 million requested early termination payment. As a result, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy will continue to operate Palisades under the current PPA with Consumers Energy, instead of shutting down in the fall of 2018 as previously planned. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022.
In January 2017, Entergy reached a settlement with New York State, several State agencies, and Riverkeeper, Inc., under which Indian Point 2 and Indian Point 3 will cease commercial operation by April 30, 2020 and April 30, 2021, respectively, subject to certain conditions, including New York State’s withdrawal of opposition to Indian Point’s license renewals and issuance of contested permits and similar authorizations. See Note 14 to the financial statements for a discussion of the impairment and related charges associated with the settlement with New York State.
The Indian Point settlement required New York State agencies to issue environmental certifications needed for license renewal and a renewed water discharge permit based on current plant configuration. It also required the New York State Attorney General and Riverkeeper to withdraw their contentions pending before the Atomic Safety and Licensing Board (ASLB). In exchange, Entergy commits to cease commercial operation of Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. These actions have been completed, all New York State approvals required for the NRC to issue renewed licenses have been granted, and the ASLB has terminated proceedings before it following the withdrawal of pending contentions. The NRC is not expected to issue renewed licenses earlier than third quarter 2018, as its staff must complete updates to the record on environmental and safety matters (a supplement to the final supplemental environmental impact statement and a supplement to the final safety evaluation report).
With the settlement concerning Indian Point, Entergy has announced plans for the disposition of all of the Entergy Wholesale Commodities nuclear power plants, including the sales of Vermont Yankee and FitzPatrick, and the earlier than previously expected shutdowns of Pilgrim, Palisades, Indian Point 2, and Indian Point 3. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” for further discussion.
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Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
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| | | | | | | | | | | | |
Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
Pilgrim (a) | | ISO-NE | | 1972 | | July 1999 | | Plymouth, MA | | 688 MW - Boiling Water | | 2032 (a) |
Indian Point 3 (b) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2015 (b) |
Indian Point 2 (b) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2013 (b) |
Vermont Yankee (c) | | IS0-NE | | 1972 | | July 2002 | | Vernon, VT | | 605 MW - Boiling Water | | 2032 (c) |
Palisades (d) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (d) |
| |
(a) | In October 2015, Entergy determined that it would close the Pilgrim plant no later than June 1, 2019, as discussed above. |
| |
(b) | In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. See below for discussion of Indian Point 2 and Indian Point 3 entering their “period of extended operation” after expiration of the plants’ initial license terms under “timely renewal.” |
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(c) | On December 29, 2014, the Vermont Yankee plant ceased power production. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, to NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. |
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(d) | In December 2016, Entergy announced that it had reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. |
In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of the fuel cycle, in January 2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon, and the sale closed in March 2017.
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process.
In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were September 28, 2013 and December 12, 2015, respectively. Authorization to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 and Indian Point 3 have now entered their “period of extended operation” after expiration of the plants’ initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency until the license renewal process has been completed. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing. The NRC is not expected to issue renewed licenses earlier than third quarter 2018. For additional discussion of the license renewal applications and the settlement with New York State, see “Entergy Wholesale Commodities
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Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Non-nuclear Generating Stations
In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for $0.5 million and realized a pre-tax loss of $0.2 million.
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
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| | | | | | | | |
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 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
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(a) | “Net Owned Capacity” refers to the nameplate rating on the generating unit. |
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(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.
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(c) | Indirectly owned through interests in unconsolidated joint ventures. |
Independent System Operators
The Pilgrim plant falls under the authority of the Independent System Operator New England (ISO-NE) and the Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of ISO-NE, NYISO, and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective 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. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. Entergy Wholesale Commodities also sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
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 receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 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
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credit, “green” credit, etc.) or otherwise to have a market value. In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the existing PPA for the Palisades plant in 2018. Entergy intended to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. In September 2017, as a result of the Michigan Public Service Commission’s order, Entergy and Consumers Energy agreed to terminate the PPA amendment agreement. Entergy intends to shut down the Palisades nuclear power plant permanently on May 31, 2022. See discussion above for additional details regarding the agreement.
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 Consolidated Edison and Consumers Energy, companies from which Entergy purchased plants, and ISO-NE, NYISO, and MISO. Substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The ISO-NE and NYISO markets are highly competitive. Entergy Wholesale Commodities has numerous competitors in New England and New York, including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet the majority of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majority of Palisades’ current output is contracted to Consumers Energy through 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. Refueling outages are generally in the spring and fall, and cause volumetric decreases during those seasons. When outdoor and cooling water temperatures are low, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of 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.
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Entergy Corporation, Utility operating companies, and System Energy
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, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants, while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formedEntergy’s non-utility operations business includes the ownership of interests 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 own nuclearnon-nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise servicethat sell 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.
Entergy Nuclear, Inc. can pursue service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. 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. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant.
TLG Services, a subsidiary of Entergy Nuclear, Inc., offers decommissioning, engineering, and related servicesproduced by those plants to nuclear power plant owners.
In September 2003, Entergy agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The original contract was to expire in 2014 corresponding to the original operating license life of the plant. In 2006 an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station. The Cooper Nuclear Station received its license renewal from the NRC in November 2010. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029. In 2017 the contract was amended so that it could not be terminated prior to December 21, 2022.
Regulation ofwholesale customers. 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.
non-utility operations
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business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy’s non-utility operations business owns interests in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy’s non-utility operations business. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
All generation owned by Entergy’s non-utility operations business falls under the authority of MISO. Customers for the sale of both energy and capacity from its owned generation and contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of the non-utility operations businesses’ owned generation and contracted power purchases are sold under a cost-based contract.
TLG Services, a subsidiary in Entergy’s non-utility operations business, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Louisiana.Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the provisions ofUtility operating companies. In addition, the System Agreement, including the rates, and the provision of transmission service to wholesale market participants. The FERC also 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.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 7065 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC which includesas to the authority to:following:
oversee •utility service;
set •utility service areas;
•retail rates and charges, including depreciation rates;
determine reasonable•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and adequateconditions of service;
control leasing;•service standards;
control •the acquisition, sale, or salelease of any public utility plant or property constituting an operating unit or system;
set rates of depreciation;
issue •certificates of convenience and necessity and certificates of environmental compatibility and public need;need, as applicable, for generating and transmission facilities;
regulate •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 recent legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to the retail rate or regulatory schemeratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to:to the following:
•utility service;
•retail rates and charges;charges, including depreciation rates;
certification of generating facilities and certain transmission projects;
certification of power or capacity purchase contracts;
audit•fuel cost recovery, including audits of the fuel adjustment charge,clause, environmental adjustment charge, and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity at or above 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control; andcontrol.
depreciation and other matters.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
facilities;•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, certain transmission projects, and certain transmission projects;distribution projects with construction costs greater than $10 million;
retail rates;•avoided cost payments to non-exempt Qualifying Facilities;
fuel cost recovery;•integrated resource planning;
depreciation rates;•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;charges, including depreciation rates;
standards•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
depreciation and other matters;•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to: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;
customer •fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects; and
•utility service areas, including extensions of service into new areas.areas;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose finescivil 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 Pilgrim, Indian Point Energy Center, Vermont Yankee, and Palisades. Substantial capital expenditures, increased operating expenses, and/or higher decommissioning costs at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.
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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, 20172023 of $183.3$205.2 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the sale of the plant, completed in March 2017. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6$1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing of the Yucca Mountain repository (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 breachedis in partial breach of 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
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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. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.
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 2021, 2022, and 2023 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE.Through 2017,2023, Entergy’s subsidiaries have won and collected on judgments against the government totaling over $500 million.approximately $1 billion.
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In April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $29 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Also in April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $44 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. In June 2015, Entergy Arkansas and System Energy appealed to the U.S. Court of Appeals for the Federal Circuit portions of those decisions relating to cask loading costs. In April 2016 the Federal Circuit issued a decision in both appeals in favor of Entergy Arkansas and System Energy, and remanded the cases back to the U.S. Court of Federal Claims. In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case, and Entergy received the payment from the U.S. Treasury in August 2016. In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case, and Entergy received payment from the U.S. Treasury in October 2016.
In May 2015 the U.S. Court of Federal Claims issued a final partial summary judgment on a portion, $21 million, of the claims in the Palisades case. The DOE did not appeal that decision, and Entergy received the payment from the U.S. Treasury in October 2015.
In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016.
In January 2016 the U.S. Court of Federal Claims issued a judgment in the amount of $49 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. In April 2016, Entergy Louisiana appealed to the U.S. Court of Appeals for the Federal Circuit the portion of that decision relating to cask loading costs. After the ANO and Grand Gulf appeal was rendered, the U.S. Court of Appeals for the Federal Circuit remanded the Waterford 3 case back to the U.S. Court of Federal Claims for decision in accordance with the U.S. Court of Appeals ruling on cask loading costs. In August 2016 the U.S. Court of Federal Claims issued a final judgment in the Waterford 3 case in the amount of $53 million, and Entergy Louisiana received the payment from the U.S. Treasury in November 2016.
In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case, reserving the issue of cask loading costs pending resolution of the appeal on the same issues in the Entergy Arkansas and System Energy cases. Entergy Louisiana received payment from the U.S. Treasury in August 2016. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana received the payment from the U.S. Treasury in January 2017. In May 2017 the U.S. Court of Federal Claims issued a final judgment in the first round River Bend damages case for $0.6 million, awarding certain cask loading costs that had not previously been adjudicated by the court.
In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulated agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016.
In September 2016 the U.S. Court of Federal Claims issued a final judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades received payment from the U.S. Treasury in January 2017.
In October 2016 the U.S. Supreme Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 received payment from the U.S. Treasury in January 2017.
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Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.
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 FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point and Vermont Yankee in 2008, at Waterford 3 in 2011, and at Pilgrim in 2015.2011. 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 for future decommissioning costs.in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposed a reinstatement of decommissioning cost recovery for ANO 2. In December 2022 the APSC ordered reinstatement of decommissioning collections for ANO 2 in accordance with the request in the November 2022 filing. In November 2023, Entergy Arkansas filed a further revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust continued to be adequately funded, but that ANO 2’s fund continued to require collections higher than those in effect. In December 2023 the APSC approved the proposed higher decommissioning collections for ANO 2.
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
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3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In October 2023 a procedural schedule was adopted that includes a hearing date in August 2024. Management cannot predict the outcome of these proceedings.
In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 20162018 the APSC ordered continuedPUCT 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 for ANO 2, while findingfund was adequate following license renewal. In July 2022, Entergy Texas filed a base rate case that ANO 1’sproposed continuation of the cessation of River Bend decommissioning was adequately funded without continued collections. In December 2017May 2023, Entergy Texas filed on behalf of the APSC ordered continued collectionsparties to the base rate case an unopposed settlement, which included an agreement to maintain Entergy Texas’s decommissioning funding for River Bend at a revenue requirement of $0. In August 2023 the PUCT issued an order accepting the unopposed settlement, including the proposed decommissioning for ANO 2, and again found that ANO 1’s decommissioning was adequately funded without continued collections. funding settlement terms.
In SeptemberDecember 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, (amongamong other things)things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted the proposal subject to refund, and appointed a settlement judge to oversee settlement negotiationsincluding the proposed decommissioning revenue requirement by letter order in the case. 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 November 2016, Entergy entered into an agreementPlant owners are required to sell 100%provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the membership interest in Entergy Nuclear Vermont Yankeetrust funds, plant owners may be required to a subsidiarytake steps, such as providing financial guarantees through letters of NorthStar. Upon closing of the sale, NorthStar will assume ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. The sale is subject to certain closing conditions, including approval from the NRC and the State of Vermont Public Utility Commission. See Note 9credit or parent company guarantees or making additional contributions to the financial statements for further discussion of Vermont Yankee decommissioning coststrusts, to ensure that the trusts are adequately funded and 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 NorthStar transaction.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy, which was completed in January 2017.NRC minimum funding requirements are met. In March 2017, Entergy sold the FitzPatrick plant to Exelon, and as part of the transaction, the FitzPatrick decommissioning trust fund, along with the decommissioning obligation for that plant, was transferred to Exelon. The FitzPatrick spent fuel disposal contract was assigned to Exelon as part of the transaction. See Note 14 to the financial statements for discussion of the FitzPatrick sale.
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In March 20172023 filings with the NRC were made for certain Entergy subsidiaries’ nuclear plants reporting on decommissioning funding.funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of thosethe 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 $127.3$165.9 million per reactor (with 10295 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to
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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 4.4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Waterford 3,Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except River Bend, Indian Point 2, Indian Point 3, and Palisades are in Column 1. Grand Gulfwhich is in Column 2. ANO 1 and 2 are
In July 2023 the NRC placed River Bend in Column 4,2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and are subjectnotice of violation related to an extensive set of required NRC inspections. Pilgrim is alsoa radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 4 and is subject to an extensive, but limited, set of required NRC inspections. See Note 8 to the financial statements for further discussion2 pending receipt of the placement of ANO 1 and 2, and Pilgrimformal report on the inspection, which is expected in Column 4 of the NRC’s matrix.first quarter 2024.
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.
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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•new source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
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• | Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
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Nonattainment•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•hazardous air pollutant emissions reduction programs;
Interstate Air Transport;
Operating permit programs and enforcement of these and other Clean Air Act programs;
Regional Haze programs; and
New and existing source standards for greenhouse gas emissions.
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. Entergy has an established process for identifying modifications requiring additional permitting approval and follows the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. In recent years, however, the EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.
In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including NSR requirements and air permits issued by the Arkansas Department of Environmental Quality. In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 a subsequent request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.
In January 2018 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. Entergy is reviewing these claims and will respond accordingly.
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•Interstate Air Transport;
Ozone Nonattainment•operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
Entergy Texas operates one fossil-fueled generating facility (Lewis Creek)•new and is inexisting source standards for greenhouse gas and other air emissions.
National Ambient Air Quality Standards
The Clean Air Act requires the process of permitting and constructing one fossil-fueled facility (Montgomery Count Power Station) in a geographic area that is not in attainment with the currently-enforced national ambient air quality standardsEPA to set National Ambient Air Quality Standards (NAAQS) for ozone. The nonattainmentozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide and requires periodic review of those standards. When an area that affects Entergy Texasfails to meet an ambient standard, it is the Houston-Galveston-Brazoria area. Areasconsidered to be in nonattainment areand is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
The Houston-Galveston-BrazoriaOzone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area was originally classified as “moderate” nonattainment under the 1997 8-hour ozone standard with an attainment date of June 15, 2010. In June 2007 the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from “moderate” to “severe” and the EPA granted the request in October 2008. In February 2015 the Texas Commission on Environmental Quality (TCEQ) submitted a request to the EPA for a finding that the Houston-Galveston-Brazoria area is not in attainment with the 1997 8-hourapplicable NAAQS for ozone. The ozone standard. The EPA issued this finding in December 2015. In April 2015 the EPA revoked the 1997 ozone NAAQS and in May 2016, the EPA issued a proposed rule approving a substitute fornonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. This redesignation indicates thatBoth Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area has attained the revoked 1997 8-hourto ozone NAAQS due to permanent and enforceable emission reductions and that it will maintain that NAAQS for 10 years from the date of the approval. Final approval, which was effective in December 2016, resulted in the area no longer being subject to any remaining anti-backsliding or non-attainment new source review requirements associated with the revoked 1997 NAAQS.
In March 2008 the EPA revised the NAAQS for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status. In April 2012 the EPA released its final non-attainment designations for the 2008 ozone NAAQS. In Entergy’s utility service area, the Houston-Galveston-Brazoria, Texas; Baton Rouge, Louisiana; and Memphis, Tennessee/Mississippi/Arkansas areas were designated as in “marginal” nonattainment. In August 2015 and January 2016, the EPA proposed determinations that the Baton Rouge and Memphis areas had attained the 2008 standard. In May 2016 the EPA finalized those determinations and extended the Houston-Galveston-Brazoria area’s attainment date for the 2008 Ozone standard to July 20, 2016 and reclassified the Baton Rouge area as attainment for ozone under the 2008 8-hour ozone standard. In December 2016 the EPA determined that the Houston-Galveston-Brazoria area had failed to attain the 2008 ozone standard by the 2016 attainment date. This finding reclassifies the Houston-Galveston-Brazoria area from marginal to “moderate.”
In October 2015 the EPA issued a final rule lowering the primary and secondary NAAQS for ozone to a level of 70 parts per billion. States were required to assess their attainment status and recommend designations to the EPA. In January 2018 the EPA proposed that the following counties and parishes in Entergy’s service territory be listed as in non-attainment: in Louisiana, Ascension Parish, East Baton Rouge Parish, West Baton Rouge Parish, Iberville Parish, and Livingston Parish; in Texas, Montgomery County. In addition to Lewis Creek in Montgomery County, Texas, Entergy owns or operates fossil-fueled generating units in East Baton Rouge Parish (Louisiana Station) and in Iberville Parish (Willow Glen), Louisiana. The EPA’s final designations are pending.could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and non-attainmentnonattainment with the new standard and, where necessary, in planning for compliance. Following designations by the EPA, states will be required to develop plans intended to return non-attainment areas to a condition of attainment. The timing for that action depends largely on the severity of non-attainment in a given area.ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. The EPA designations for counties in attainment and nonattainment were originally due in June 2012, but the EPA indicated that it would delay designations except for those areas with existing monitoring data from 2009 to 2011 indicating violations of the new standard. In August 2013 the EPA issued final designations for these areas. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana isare designated as non-attainment for the SO2
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1-hour national ambient air quality standard of 75 parts per billion. Entergy does not have a generation asset in that parish. In July 2016 the EPA finalized another round of designations for areas with newly monitored violations of the 2010 standard and those with stationary sources that emit over a threshold amount of SO2. Counties and parishes in which Entergy owns and operates fossil generating facilities that were included in this round of designations include Independence County and Jefferson County, Arkansas and Calcasieu Parish, Louisiana. Independence County and Calcasieu Parish were designated “unclassifiable,” and Jefferson County was designated “unclassifiable/attainment.” In August 2015 the EPA issued a final data requirement rule for the SO2 1-hour standard. This rule will guide the process to be followed by the states and the EPA to determine the appropriate designation for the remaining unclassified areas in the country.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 January 2018March 2021 the EPA published a final rule designating a third round of attainmentEast Baton Rouge, St. Charles, St. James, and non-attainment areas. Evangeline Parish,West Baton Rouge parishes in Louisiana was designated non-attainment. 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 does not have a generation asset in that parish. Additional capital projects or operational changes may be requiredcontinues to continue operating Entergy facilities in areas eventually designated as in non-attainment of the standard or designated as contributing to non-attainment areas.monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. In April 2023 the EPA issued a regulatory proposal to revise portions of the MATS rule, including a proposed reduction to the emission limit for filterable particulate matter. If finalized, the proposed lower filterable particulate matter emission limitation could require additional capital investment and/or additional other operation and maintenance costs at Entergy’s coal-fired generating units. Entergy is closely monitoring this rulemaking, in part through its various trade associations.
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Good Neighbor Plan/Cross-State Air Pollution Rule
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
Based on several court challenges, CAIR and its subsequent versions, now known as the Cross StateCross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In July 2015 the D.C. Circuit invalidated the allowance budgets created byJune 2023 the EPA for several states, including Texas, and remanded that portion ofpublished its final Federal Implementation Plan (FIP), known as the rule to the EPA for further action. The court did not stay or vacate the rule in the interim. CSAPR remains in effect.
The CSAPR Phase 1 implementation became effective January 1, 2015. Entergy has developed a compliance plan that could, over time, include both installation of controls at certain facilities and an emission allowance procurement strategy.
In September 2016 the EPA finalized the CSAPR Update RuleGood Neighbor Plan, to address interstate transport for the 20082015 ozone NAAQS. StartingNAAQS which would increase the stringency of the CSAPR program in 2017all four of the final rule will require reductionsstates where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Entergy is currently assessing its compliance options for the FIP. Prior to issuance of the FIP, in summer nitrogen oxides (NOx) emissions. SeveralFebruary 2023 the EPA issued related State Implementation Plan (SIP) disapprovals for many states, including Arkansasthe four states in which the Utility operating companies operate, and Texas,these SIP disapprovals are the subject of many legal challenges, including a petition for review filed a challengeby Entergy Louisiana challenging the disapproval of Louisiana’s SIP. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the Good Neighbor Plan will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2024. The final FIP also is subject to the Update Rule, which remains pending.numerous legal challenges.
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 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.
InThe 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 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, NISCO, and Ninemile. Responses to the information collection requests were submitted to the respective state agencies. Louisiana issued its draft SIP which did not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality prepared a state implementation plan (SIP) for Arkansas facilities(ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to implement its obligations under the CAVR. In April 2012 the EPA finalized a decisionfor review. The ADEQ reviewed Entergy’s Independence plant but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The
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addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas plan, including the emission limits for NOx and SO2 at White Bluff. In April 2015 the EPA published a proposed federal implementation plan (FIP) for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2 and NOx limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units at a later date.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP required an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. In November 2016, Entergy and other interested parties, including the State of Arkansas, filed petitions for administrative reconsideration and stay at the EPA as well as petitions for judicial review in the U.S. Court of Appeals for the Eighth Circuit. The Eighth Circuit continues to review its prior grant of the government’s motion to hold the appeal litigation in abeyance pending settlement discussions and pending the State’s development of a SIP that, if approved by the EPA, would replace the FIP. The state has proposed its replacement SIP in two parts: Part I considers NOx requirements, and Part II considers SO2 requirements. The EPA approved the Part I NOx SIP in January 2018. Arkansas has proposed a Part II SIP which is still under consideration at the state level. The public comment period on Part II ended on February 2, 2018.
In Louisiana, Entergy worked with the LouisianaMississippi Department of Environmental Quality (LDEQ)also did not meet the July 31, 2021 SIP submission deadline and continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to reviseeither approve a SIP submitted by the Louisiana SIPstate or issue a final federal plan.
Greenhouse Gas Emissions
In April 2021, President Biden announced a target for regional haze, which was disapprovedthe United States in partconnection with the United Nations’ “Paris Agreement” on climate change. The target consists of a 50-52 percent reduction in 2012. The LDEQ submittedeconomy-wide net greenhouse gas emissions from 2005 levels by 2030. President Biden has also stated that a revised SIPgoal of his administration is for the electric power industry to decarbonize fully by 2035.
Consistent with the Biden administration’s stated climate goals, in February 2017. In May 20172023 the EPA proposed to approve a majority of the revisions. In September 2017 the EPA issued a proposed SIP approval for the Nelson plant, requiring an emission limitation consistent with the use of low-sulfur coal, with a compliance date three yearsseveral rules regulating greenhouse gas emissions from the effective date of the final EPA approval. The EPA’s final approval decision was issued in December 2017 and is on appeal to the U.S. Court of Appeals for the Fifth Circuit.
New and Existing Source Performance Standards for Greenhouse Gas Emissions
As a part of a climate plan announced in June 2013, the EPA was directed to (i) reissue proposed carbon pollution standards for new power plants by September 20, 2013, with finalization of the rules to occur in a timely manner; (ii) issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed, and existing power plants no later than June 1, 2014; (iii) finalize those rules by no later than June 1, 2015; and (iv) include in the guidelines addressing existing power plants a requirement that states submit to the EPA the implementation plans required under Section 111(d) of the Clean Air Act and its implementing regulations by no later than June 30, 2016. In January 2014 the EPA issued the proposed New Source Performance Standards rule for new sources. In June 2014 the EPA issued proposed standards for existing power plants. Entergy was actively engaged in the rulemaking process, and submitted comments to the EPA in December 2014. The EPA issued the final rules for both new and existing sourcescoal and gas-fired power plants. If finalized, the proposed requirements for existing “large and frequently used” gas turbine generating units could require significant investments in CO2 emission reduction technologies at certain of Entergy’s existing gas turbine units with a capacity of greater than 300 MW per combustion turbine and which operate at an annual capacity factor of greater than 50 percent. Comments on the proposed rules were submitted in August 2015,2023 and they were publishedEntergy is monitoring the rulemaking, in the Federal Registerpart through its trade associations.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in October 2015. The existing source rule, also called the Clean Power Plan, requires states to develop plans for compliance with the EPA’slow-emitting generation technologies, Entergy has a low overall carbon dioxide emission standards.“intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In February 2016 the U.S. Supreme Court issued a stay halting the effectivenessanticipation of the rule untilimposition of carbon dioxide emission limits on the rule is reviewedelectric 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 D.C. Circuitrecommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and by the U.S. Supreme Court, if further review is granted.metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. In March 2017 the current administration issued an executive order entitled “Promoting Energy Independence and Economic Growth” instructing the EPASeptember 2020, Entergy announced a commitment to review and then to suspend, revise, or rescind the Clean Power Plan, if appropriate. The EPA subsequently asked the D.C. Circuit to hold the challenges to the Clean Power Plan and theachieve net-zero greenhouse gas new source performance standardsemissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in abeyance and signed a notice of withdrawalPart I, Item 1A for discussion of the proposed federal plan, model trading rules,risks associated with achieving these climate goals. Entergy’s comprehensive, third party verified greenhouse gas inventory and the Clean Energy Incentive Program. The court placed the litigation in abeyance in April 2017. The EPA Administrator also sent a letter to the affected governors explaining that statesprogress against its voluntary goals are not currently required to meet Clean Power Plan deadlines, some of which have passed. In October 2017 the EPA proposed a new rule that would repeal the Clean Power Planpublished on the grounds that it exceeds the EPA’s statutory authority under the Clean Air Act. In Decemberits website.
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2017 the EPA issued an advanced notice of proposed rulemaking regarding section 111(d), seeking comment on the form and content of a replacement for the Clean Power Plan, if one is promulgated. Entergy will continue to be engaged in this rulemaking process.
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, 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;
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• | introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
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•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to 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 mandatory 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 Federalfederal laws and regulations;
•implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United Statesregional cap and similar actions intrade programs to limit carbon dioxide and other regions of the United States;greenhouse gases;
•efforts on the local, state, and federal level to codify renewable portfolio standards, a clean energy standard,standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs;polychlorinated biphenyls (PCBs) and increased regulation of per- and polyfluorinated substances or other chemicals;
•efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissionsenvironmental, 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; and
•the regulation of the management, disposal, and beneficial reuse of coal combustion residuals.residuals; and
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low-emitting gas-fired and nuclear 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•the regulation of the impositionmanagement and disposal and recycling of carbon dioxide emission limits on the electric industry in the future, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included establishment of a formal program to stabilize power plant carbon dioxide emissions at 2000 levels through 2005,equipment associated with renewable and Entergy succeeded in reducing emissions below 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 and 35.6 million tons in 2005. In 2006, Entergy changed its method of calculating emissions to include emissions from controllable power purchasesclean energy sources such as well as its ownership share of generation. Entergy established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 46.1 million tons in 2011, 45.5 million tons in 2012, 46.2 million tons in 2013, 42.4 million tons in 2014, 39.5 million tons in 2015, 42.5 million tons in 2016, and 39.9 million tons in 2017. The decreaseused solar panels, wind turbine blades, hydrogen usage, or battery storage.
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in this number from 2014 to 2015 was largely attributable to the impact on the calculation methodology of the Utility operating companies’ transition into the MISO system. Participation in this system resulted in fewer power purchases being classified as “controllable” and thus included in the calculation of the emissions total.
Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s annual CO2 emissions audit is also third-party verified, and that certification is made available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2017 was listed on the North American Index.
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 (NPDES) permit program, section 402, and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
NPDES Permits and Section 401 Water Quality Certifications
NPDES permits are subject to renewal every five years. Consequently, Entergy is currently in various stagesFederal Jurisdiction of Waters of the data evaluation and discharge permitting process for its power plants. United States
For thirteen years, Entergy participated in an administrative permitting process withIn June 2020 the New York State DepartmentEPA’s revised definition of Environmental Conservation (NYSDEC) for renewalwaters of the Indian Point 2 and Indian Point 3 discharge permit. That proceeding recently was settled along with other ongoing proceedings. For a discussionUnited States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of the recent Indian Point settlement, see “Entergy Wholesale Commodities Authorization to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
316(b) Cooling Water Intake Structures
The EPA finalized regulations in July 2004 governing the intake of water at large existing power plants employing cooling water intake structures. The rule sought to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states challenged various aspects of the rule. After litigation, the EPA issued a new final 316(b) rule in August 2014. Entergy is developing a compliance plan for each affected facility in accordance with the requirements of the final rule.
Entergy filed a petition for review of the final rule as a co-petitioner with the UtilityClean Water Act Group. The U.S. Court of Appeals for the Second Circuit heard oral argument in September 2017. A decision is expected in 2018.
Coastal Zone Management Act
Beforejurisdiction, as compared to a federal licensing agency (such as the NRC) may issue a major license or permit for an activity within the federally designated coastal zone, the agency must be satisfied that the requirements of the Coastal Zone Management Act (CZMA), as applicable, have been met. In many cases, CZMA requirements are satisfied by the state’s written concurrence with a “consistency determination” filed by the federal license applicant explaining why the activity proposed to be federally licensed is consistent with the state’s coastal management program. For a discussion of the recent Indian Point settlement, including the CZMA proceedings related to Indian Point license renewal, see “Entergy
2015
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Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporationdefinition which had been stayed by several federal courts. In August 2021 a federal district court vacated and Subsidiaries Management’s Financial Discussion and Analysis.
Federal Jurisdiction of Waters ofremanded the United States
In September 2013 theNWPR for further consideration. The EPA and the U.S. Army Corps of Engineers announced(Corps) subsequently issued a statement that the intentionagencies would revert to proposepre-2015 regulations pending a rule to clarify federal Clean Water Act jurisdiction overnew rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States. The announcement was made in conjunctionStates (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the EPA’s release of a draft scientific report on the “connectivity” of waters that the agency said would inform the rulemaking. This reportpre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was finalized in January 2015. The final rulesubject to multiple legal challenges and was published in the Federal Register in June 2015. The rule could significantly increase the number and types of waters included in the EPA’s andenjoined from implementation or enforcement throughout Entergy’s utility service territory. In May 2023 the U.S. Army Corps of Engineers’ jurisdiction, which in turn could pose additional permitting and pollutant management burdens on Entergy’s operations. The final rule has been challenged in various federal courts by several parties, including most states. In August 2015 the DistrictSupreme Court for North Dakota issued a preliminary injunction stayingdecision limiting the new rulescope of federal jurisdiction over wetlands, and in 13 states, including Arkansas. In October 2015 the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the rule. In February 2017 the current administration issued an executive order instructingSeptember 2023 the EPA and the U.S. Army Corps of Engineers to review the Waters of the United Statesissued a final rule and to revise or rescind, as appropriate. In June 2017 the EPA and the U.S. Army Corps of Engineers released a proposed rule that rescinds the June 2015 rule and recodifies the definition of “waters of the U.S.” that was in effect prior to the 2015 rule. The administration is expected to propose a definition of “waters of the U.S.” at a later date. In January 2018incorporating the Supreme Court determined thatdecision. Most notably, the Sixth Circuit lacked jurisdiction over the petition to review the 2015 rule and that the challenges should be heard in the federal district court. The matter has been remanded to the Sixth Circuit, whichexclusion for waste treatment systems is expected to lift the nationwide stay. After the Supreme Court decision, the EPA and the U.S. Army Corps of Engineers finalized a rule delaying the applicability date of the 2015 rule to early 2020. In February 2018 the states of Louisiana, Mississippi, and Texas filed suit in Texas federal district court seeking a preliminary injunction of the 2015 rule. Entergy will continue to monitor this rulemaking and litigation.retained.
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, Indian Point, Palisades, Pilgrim, Grand Gulf, Vermont Yankee, 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.
In February 2016, Entergy disclosed that elevated tritium levels had been detected in samples from several monitoring wells that are part of Indian Point’s groundwater monitoring program. Investigation of the source of elevated tritium has determined that the source is related to a temporary system to process water in preparation for the regularly scheduled refueling outage at Indian Point 2. The system was secured and is no longer in use and additional measures have been taken to prevent reoccurrence should the system be needed again. In June 2016, Indian Point detected trace amounts of cobalt 58 in a single well. This was associated with the draining and disassembly of a temporary heat
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Entergy Corporation, Utility operating companies, and System Energy
exchanger operated in support of the Indian Point 2 outage. Oversight by NRC and other federal/state government bodies continues. The NRC has issued a green notice of violation related to the adequacy of Entergy’s controls to prevent the introduction of radioactivity into the site groundwater. Entergy has completed all required corrective actions and expects the NRC to close the notice of violation by March 2018.
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.facilities including nuclear facilities that have been 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 2010April 2015 the EPA issued a proposed rule onpublished the final 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 RCRA Subtitle C; or (2)(CCR) rule 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 RCRAResource Conservation and Recovery Act Subtitle D.
The final regulations createcreated new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria.criteria but excluded CCRs that are beneficially reused in certain processes. 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.needed. As of December 31, 2017, Entergy’s2023, Entergy has recorded asset retirement obligations related to CCR management of $8.6 million, including $3.9 million at Entergy Arkansas, $1.8 million at Entergy Louisiana, $1.1 million at Entergy Mississippi, and $1.3 million at Entergy Texas.$28 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 submitPursuant to the EPA proposals for a permit programs. In September 2017Rule, 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 EPA agreed to reconsider certain provisions of the CCR rule in light of the WIIN Act. The EPAarea, but has not yet initiated a new round of rulemakingindicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and did not extenddetection monitoring will continue as the existing mid-October 2017 groundwater monitoring deadline. Entergy met the existing monitoring deadline, is monitoring state agency actions, and will participate in the regulatory development process.
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. Entergy is taking actionConsequently, in order to addressmove away from using the operationalrecycle ponds, White Bluff and regulatory managementIndependence each installed a new permanent bottom ash handling system that does not fall under the CCR rule. As of these facilities. Entergy also has monitored levelsNovember 2020, both sites are operating the new system and no longer are sending waste to the recycle ponds. Each site commenced closure of constituents inits two recycle ponds (four ponds total) prior to the groundwater monitoring system surrounding its coal combustion residual landfills at these locations that require reporting and additional monitoring. Reporting has occurred as required, and monitoring will continue.April 11, 2021 deadline under the finalized CCR rule for unlined recycle ponds. Any potential
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Entergy Corporation, Utility operating companies, and System Energy
requirements for corrective action or operational changes under the new EPACCR rule are currently beingcontinue to be assessed. Moreover,Notably, ongoing litigation has resulted in the rule is currently underEPA’s continuing review atof the EPA for potential changes, andrule. Consequently, the nature and cost of anyadditional corrective action requirements may depend, in part, on the outcome of the EPA’s review.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Additionally, all three sites are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines (ELG). The nature, cost, and timing of those compliance measures depends on the guidance included in the final ELG rule, which is expected by mid-2024.
In May 2023 the EPA released a proposed rule establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (i.e., non-containerized CCR located at a regulated CCR facility). Entergy does not have any legacy impoundments; however, the proposed definition of CCR management units appears to regulate on-site areas where CCR was beneficially used. This is contrary to the current CCR rule which exempts beneficial uses that meet certain criteria. Comments on the proposed rule were submitted in July 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Other Environmental MattersUtility Regulatory Risks
Entergy Louisiana•The terms and Entergy Texasconditions of service, including electric and gas rates, of the Registrant Subsidiaries are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in lengthy litigation, and uncertainty as to ultimate results.
Entergy Louisiana, as successor in interest•Entergy’s business could experience adverse effects related to Entergy Gulf States Louisiana, currently is involvedchanges to state or federal legislation or regulation, or experience risks associated with participation in the second phaseMISO markets and allocation of the remedial investigationtransmission upgrade costs.
•The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of the Lake Charles Service Center site, locateddelay or disallowance in Lake Charles, Louisiana. regulatory proceedings.
•A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the propertydelay or failure in recovering amounts for disposal. The same area also has been usedstorm restoration costs incurred as a landfill. In 1999,result of severe weather could have material effects on Entergy Gulf States, Inc. signedand its Utility operating companies affected by severe weather.
•Weather, economic conditions, technological developments, and other factors may have a second administrative consent order withmaterial impact on electricity and gas usage and otherwise materially affect the EPA to perform a removal action at the site. In 2002 approximately 7,400 tonsUtility operating companies’ results of contaminated soiloperations.
Nuclear Operating, Shutdown, and debris were excavatedRegulatory Risks
•The results of operations, financial condition, and disposedliquidity of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006 and is continuing. The EPA released the second Five Year Review in 2015. The EPA indicated that the current remediation technique was insufficient and that Entergy would need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and suggesting installation of a waterloo barrier. The estimated cost for this remedy is approximately $2 million. Entergy is awaiting comments and direction from the EPA on the Focused Feasibility Study and potential remedy selection. In early 2017 the EPA indicated that the new remedial method, a waterloo barrier, may not be necessary and requested revisions to the Focused Feasibility Study. The EPA plans to provide comments on the revised 2017 Focused Feasibility Study in the next Five Year Review in 2020. Entergy is continuing discussions with the EPA regarding the ongoing actions at the site.
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination exists at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas respondedSystem Energy could be materially affected by the following:
◦inability to an information request fromconsistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last materially longer than anticipated or unplanned outages;
◦risks related to the TCEQpurchase of uranium fuel (and its conversion, enrichment, and continuefabrication);
◦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 cooperate in this investigation. Entergy Louisianaoperating and Entergy Texas joined a group of PRPs responding to site conditions in cooperationmaintaining their nuclear power plants;
◦the costs associated with the Statestorage of Texas, creating cost allocation models basedthe 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 and/or assessments imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets 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.
Business Risks
•Entergy and the Registrant Subsidiaries depend on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contributeaccess to the remediation of contaminated soilcapital markets and, groundwater at times, may face potential liquidity constraints. Disruptions in the sitecapital and credit markets or a downgrade in a measure proportionateEntergy’s or its Registrant Subsidiaries’ credit ratings could, among other things, adversely affect their ability to those companies’ involvement at the site, while Entergy Arkansas likely will pay a de minimis amount. Current estimates, although variable depending on ultimate remediation designmeet liquidity needs, or to access capital to operate and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Remediation activities continue at the site.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The Texas Commission on Environmental Quality (TCEQ)grow their businesses, and the National Response Center were immediately notified, and TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $2.2 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements. In July 2017,
cost of capital.
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Entergy Corporation, Utility operating companies, and System Energy
•The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals or commitments, among other potential causes.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs (i) to fulfill their obligations related to environmental and other matters or (ii) related to reliability standards.
•Entergy could be negatively affected by the effects of climate change, including physical risks, such as increased frequency and intensity of hurricanes, availability of water, droughts, and other severe weather and wildfires, and transition risks, such as environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, or increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding of such benefit plans and result in increased benefit plan costs.
•The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ physical infrastructure or technology systems may adversely affect Entergy’s business and results of operations.
•Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
•Significant increases in commodity prices, other materials and supplies, and operation and maintenance expenses may adversely affect Entergy’s results of operations, financial condition, and liquidity.
•The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds, which financing may not be available on terms acceptable to System Energy when required.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
•The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy entered into the Voluntary Cleanup Programis an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with TCEQ. Additional direction is expected from TCEQ regarding final remediation requirements for the site.
approximately 24,000 MW of electric generating capacity. Entergy
In May 2015 a transformer at the Indian Point facility failed, resulting delivers electricity to approximately 3 million Utility customers in a fire and the release of non-PCB oil to the ground surface. The fire was extinguished by the facility’s fire deluge system. No injuries occurred due to the transformer failure or company response. An estimated 3,000 gallons of oil were released into the facility’s discharge canal and the environment surrounding the transformer and discharge canal, including the Hudson River, as a result of the failure, fire, and fire suppression. Once the fire was extinguished, Indian Point personnel and contractors began recovering free-product from the damaged transformer, the transformer containment moat, and the area surrounding the transformer. The United States Coast Guard designated Entergy as the responsible party under the Oil Pollution Act of 1990 and assessed a $1,000 civil penalty for the discharge of oil into navigable waters. As required, Entergy established a claims process including a voluntary hotline. Entergy received no reports to the voluntary hotline or claims under the established claims process. In September 2016, Indian Point personnel identified an oil sheen in the discharge canal. Further investigation revealed that an estimated 600 gallons of lubricating oil had leaked from the Indian Point 3 turbine system. The leaking component has been taken out of service and no oil has been discovered in the Hudson River. In October 2016 the New York Department of Environmental Conservation issued two notices of violation, one for each of these events, and a proposed order on consent for the 2015 event. In January 2017, Entergy and the New York Department of Environmental Conservation resolved this matter with an order on consent. Pursuant to the order, Entergy paid approximately $600 thousand in civil penalties, natural resource damages, and oversight costs. Additionally, Entergy repaired a section of the discharge canal wall and will conduct daily visual inspections of the discharge canal wall to help identify additional material erosion or material structural deficiencies. Entergy has completed all compliance obligations under the consent order and the Department of Environmental Conservation closed the matter in December 2017.
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 inArkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $12.1 billion in 2023 and had approximately 12,000 employees as of December 31, 2023.
Entergy operates primarily through a single reportable segment, Utility. The Utility segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, have demonstratedand Louisiana, including the City of New Orleans; and operation of a willingnesssmall natural gas distribution business in portions of Louisiana. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Entergy completed its multi-year strategy to grant large verdicts,exit the merchant nuclear power business in 2022 and upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable segment. See Note 13 to the financial statements for discussion of and financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow its utility business through a customer-centric approach designed to understand and meet customer needs, creating value for all of its key stakeholders, including punitive damages,customers, communities, employees, and owners. As part of its strategy, Entergy invests significant capital to plaintiffs in personal injury, property damage,support customer growth and business tort cases. its customers’ growing demands for greater reliability, resilience, and clean energy, while remaining focused on affordability. Entergy manages risks by ensuring its Utility investments are customer-driven, the result of robust analysis, supported by broad stakeholder outreach and progressive regulatory constructs, and executed with disciplined project management. Further, Entergy continues to integrate key sustainability elements, including social responsibility and good governance, into every decision it makes.
Utility
The litigation environment in these states poses a significant business risk to Entergy.
Ratepayer and Fuel Cost Recovery Lawsuits (Entergy Corporation,Utility segment includes five retail electric utility subsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Texas. These companies generate, transmit, distribute, and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, Attorney General Complaint
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. See Note 2 to the financial statements“MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for a discussion of this proceeding.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana,the planned sale of the Entergy New Orleans and Entergy Texas)
See Note 8Louisiana gas distribution businesses. 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 the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, 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, Entergy Texas, andthe City Council. System Energy)Energy is regulated by the FERC because all of its transactions are at wholesale. The Utility has a diverse power generation portfolio, including increasingly carbon-free energy sources, which is consistent with Entergy’s strong support for the environment.
See Note 8 to the financial statements for a discussion of these proceedings.
Part I Item 1
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Customers
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2017, Entergy subsidiaries employed 13,504 people.
|
| | |
Utility: | |
|
Entergy Arkansas | 1,278 |
|
Entergy Louisiana | 1,713 |
|
Entergy Mississippi | 737 |
|
Entergy New Orleans | 274 |
|
Entergy Texas | 616 |
|
System Energy | — |
|
Entergy Operations | 3,361 |
|
Entergy Services | 3,264 |
|
Entergy Nuclear Operations | 2,211 |
|
Other subsidiaries | 50 |
|
Total Entergy | 13,504 |
|
Approximately 4,600 employees are represented by the International Brotherhood of Electrical Workers,2023, the Utility Workers Unionoperating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 730 | | | 24 | | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,105 | | | 37 | | | 96 | | | 47 | |
| Entergy Mississippi | Portions of Mississippi | | 459 | | | 15 | | | | | |
| Entergy New Orleans | City of New Orleans | | 208 | | | 7 | | | 108 | | | 53 | |
| Entergy Texas | Portions of Texas | | 512 | | | 17 | | | | | |
| Total | | | 3,014 | | | 100 | | | 204 | | | 100 | |
Electric and Natural Gas Energy Sales
Electric Energy Sales
The total electric energy sales of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, Fire Professionals of America.
Availability of SEC filings and other information on Entergy’s website
Entergy electronically files reportsUtility operating companies are subject to seasonal fluctuations, with the SEC, including annual reportspeak sales period normally occurring during the third quarter of each year. On August 23, 2023, Entergy reached a 2023 peak demand of 23,319 MWh, compared to the 2022 peak of 22,301 MWh recorded on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. June 24, 2022. Selected electric energy sales data for 2023 is shown in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (GWh) |
| Sales to retail customers | 22,481 | | | 57,681 | | | 12,854 | | | 5,696 | | | 21,146 | | | — | | | 119,858 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 2,218 | | | 4,406 | | | — | | | — | | | — | | | 10,574 | | | — | |
| Others | 5,777 | | | 1,534 | | | 4,598 | | | 2,818 | | | 462 | | | — | | | 15,189 | |
| Total | 30,476 | | | 63,621 | | | 17,452 | | | 8,514 | | | 21,608 | | | 10,574 | | | 135,047 | |
| Average use per residential customer (kWh) | 12,561 | | | 14,893 | | | 14,226 | | | 12,610 | | | 14,941 | | | — | | | 14,089 | |
(a)Includes the effect of intercompany eliminations.
The public may read and copy any materials that Entergy files withfollowing table illustrates the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also 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.
Entergy uses its website, http://www.entergy.com,Utility operating companies’ 2023 combined electric sales volume as a routine channel for distributionpercentage of important information, including news releases, analyst presentationstotal electric sales volume, and financial information. Filings made with2023 combined electric revenues as a percentage of total 2023 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 26.9 | | 38.4 |
| Commercial | | 20.9 | | 25.3 |
| Industrial (a) | | 39.1 | | 26.8 |
| Governmental | | 1.8 | | 2.3 |
| Wholesale/Other | | 11.3 | | 7.2 |
(a)Major industrial customers are primarily in the SEC are postedpetroleum refining and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.chemical industries.
Part I Item 1A & 1B1
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Natural Gas Energy Sales
RISK FACTORS
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 8,917,149 and 6,130,048 Mcf, respectively, of natural gas to retail customers in 2023. In 2023, 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 2023.
Investors should
Following is data concerning Entergy New Orleans’s 2023 retail operating revenue sources:
| | | | | | | | | | | | | | |
| Customer Class | | % of Electric Operating Revenue | | % of Natural Gas Operating Revenue |
| Residential | | 48 | | 51 |
| Commercial | | 35 | | 26 |
| Industrial | | 5 | | 17 |
| Governmental/Municipal | | 12 | | 6 |
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 and System Energy’s retail rate mechanisms are discussed below.
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| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy Arkansas | | $10.1 (a) | | 9.15% - 10.15% | | 5.62% | | 38.7% (b) | | - forward test year formula rate plan - riders: fuel and purchased power, MISO, capacity, Grand Gulf, energy efficiency |
| Entergy Louisiana (electric) | | $15.7 (c) | | 9.0% - 10.0% | | 6.66% | | 49.51% | | - formula rate plan through 2022 test year - riders/specific recovery: MISO, capacity, transmission, fuel, distribution, tax reform |
| Entergy Louisiana (gas) | | $0.15 (d) | | 9.3% - 10.3% | | 6.93% | | 51.83% | | - gas rate stabilization plan - rider: gas infrastructure |
| Entergy Mississippi | | $4.2 (e) | | 9.74% - 11.88% | | 7.06% | | 46.76% | | - formula rate plan with forward-looking features - riders: fuel, Grand Gulf, MISO, unit power cost, storm damage, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit, power management |
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| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy New Orleans (electric) | | $1.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity costs |
| Entergy New Orleans (gas) | | $0.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - rider: purchased gas |
| Entergy Texas | | $4.4 (h) | | 9.57% | | 6.61% | | 51.2% | | - rate case and cost recovery riders - riders: fuel, capacity, cost recovery riders (distribution, transmission, and generation), rate case expenses, advanced metering infrastructure surcharge, and tax reform, among others |
| System Energy | | $1.74 (i) | | 10.94% (j) | | 8.54% | | 59.5% (j) | | - monthly cost of service |
(a)Based on 2024 test year.
(b)Based on $1.9 billion in accumulated deferred income taxes at a 0% cost rate included in the weighted-average cost of capital calculation.
(c)Based on December 31, 2022 test year and excludes approximately $300 million of transmission plant investment included in the transmission recovery mechanism and approximately $200 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of net accumulated deferred tax liability items included in the tax reform adjustment mechanism.
(d)Based on September 30, 2022 test year.
(e)Based on 2023 forward test year.
(f)Based on December 31, 2022 test year and known and measurables through December 31, 2023.
(g)In October 2023 the City Council approved a three-year extension of Entergy New Orleans’s formula rate plan, modified to reflect a 55% fixed capital structure for rate setting purposes.
(h)Based on December 31, 2021 test year.
(i)Based on calculation as of December 31, 2023.
(j)Effective July 2022, Entergy Mississippi’s bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, and a rate base reduction for the advance collection of sale-leaseback rental costs. See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
Entergy Arkansas
Formula Rate Plan
Between base rate cases, Entergy Arkansas is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize a forward test year. Entergy Arkansas is subject to a maximum rate change 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
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2015, the APSC approved the formula rate plan tariff proposed by Entergy Arkansas including its use of a projected year test period and an initial five-year term. The initial five-year term expired in 2021. As granted by Arkansas law, Entergy Arkansas obtained APSC approval of the extension of the formula rate plan tariff for an additional five-year term, through 2026. As part of the settlement of the 2023 formula rate plan proceeding, Entergy Arkansas agreed to file its next base rate case no later than February 2026. If Entergy Arkansas’s formula rate plan were terminated, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review carefullymechanism.
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
Production Cost Allocation Rider
Entergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of System Agreement proceedings.
Other
In June 2022 the APSC approved Entergy Arkansas’s compliance tariff filing for a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The APSC approved an initial offering of 100 MW of solar capacity to be made available under this tariff.
In June 2023 the APSC approved Entergy Arkansas’s Go ZERO tariff, which provides participating industrial and commercial customers the opportunity to chose from a number of clean energy options to help them achieve their sustainability goals.
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. In 2021 the LPSC approved a settlement extending the formula rate plan for test years 2020, 2021 and 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and certain distribution investments, among other items. In August
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2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years, test years 2023-2025, which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study, with a 2024-2026 test year formula rate plan. The application complies with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service/rate case. See Note 2 to the financial statements for a discussion of Entergy Louisiana’s application.
Fuel and Purchased Power Cost 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. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension
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allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then-current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the
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return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider.
In 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.
In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the annual power management and grid modernization riders effective January 2023.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
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Other
In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule.
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. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.
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.
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 filings to recover storm-related costs.
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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 and Purchased Power Cost 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. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 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. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.
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 to be recovered through a purchased power capacity rider. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs. In 2023, the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through a purchased power capacity rider.
Transmission, Distribution, and Generation 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 permitted 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. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their
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distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Other
In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.
As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.
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
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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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric
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service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2024-2058.
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, 2023 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,036 | | | 1,548 | | | 521 | | | 1,825 | | | 969 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,798 | | | 5,594 | | | 2,728 | | | 2,137 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,904 | | | 1,744 | | | 641 | | | — | | | 417 | | | — | | | 102 | |
| Entergy New Orleans | | 662 | | | 635 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,234 | | | 990 | | | 1,994 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,245 | | | — | | | — | | | 1,245 | | | — | | | — | | | — | |
| Total | | 23,879 | | | 10,511 | | | 5,884 | | | 5,207 | | | 1,975 | | | 73 | | | 229 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,775 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 7,963 MW of new long-term resources and the deactivation of about 4,241 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
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products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•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. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC’s approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the St. Jacques facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar
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facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
•Entergy Louisiana expects to start construction on the 49 MW Sterlington Solar project in the fourth quarter 2024, located in Sterlington, Louisiana. The facility is expected to achieve commercial operation in January 2026.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from a 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 and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a 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 and TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, executed a 10-year agreement to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
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•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
•In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
•In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC
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requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
•In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, 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 as early as June 2026.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. Entergy Louisiana selected a combination of PPA and build own transfer resources in March 2023 some of which have been executed and are noted above, and negotiation of definitive agreements for the remaining resources are in progress.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2023, and negotiation of definitive agreements are in progress for all resources.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including among others:
•In March 2016, Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) 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). The facility is located near El Dorado, Arkansas and has been in operation since July 2003;
•In October 2019, Entergy Mississippi’s acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The facility is located in Choctaw County and has been in operation since July 2003;
•In November 2020, Entergy Louisiana’s acquisition of 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. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
•In June 2021, Entergy Texas’s acquisition of 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. The facility has been in operation since January 2010; and
•In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC voted to approve this project and in September 2023, Entergy Louisiana reported
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to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. A procedural schedule has not yet been set.
In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas’s proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A
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paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas’s rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC’s order.
In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to the transmission system which operates at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined-cycle combustion turbine generators and reciprocating internal combustion engine generators that are fueled by natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that participate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include generating and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2023, 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, 2023, 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
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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 average fuel cost per kWh for the Utility operating companies and System Energy for the years 2021-2023 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2023 | | (Cents Per kWh) |
| Entergy Arkansas | | 1.98 | | | 0.50 | | | 3.09 | | | 1.98 | | | 11.57 | | | 0.77 | |
| Entergy Louisiana | | 2.34 | | | 0.60 | | | 3.22 | | | 10.38 | | | 3.76 | | | 2.50 | |
| Entergy Mississippi | | 2.21 | | | — | | | 2.82 | | | 0.03 | | | 5.86 | | | 1.84 | |
| Entergy New Orleans (c) | | 2.05 | | | — | | | — | | | 3.24 | | | — | | | 2.33 | |
| Entergy Texas | | 2.29 | | | — | | | 3.17 | | | 2.25 | | | 5.64 | | | 3.18 | |
| System Energy | | — | | | 0.68 | | | — | | | — | | | — | | | — | |
| Utility | | 2.25 | | | 0.58 | | | 3.06 | | | 6.14 | | | 4.03 | | | 2.61 | |
| | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $0.1 million in 2023, $2.9 million in 2022, and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2023 and projected 2024 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | 1 | % | | 57 | % | | 9 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 47 | % | | 7 | % | | 20 | % | | 2 | % | | 2 | % | | 10 | % | | 12 | % |
| Entergy Mississippi | 63 | % | | 1 | % | | 23 | % | | 7 | % | | 1 | % | | — | % | | 5 | % |
| Entergy New Orleans | 55 | % | | 1 | % | | 36 | % | | 1 | % | | 2 | % | | 1 | % | | 4 | % |
| Entergy Texas | 32 | % | | 25 | % | | 6 | % | | 3 | % | | — | % | | 4 | % | | 30 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 43 | % | | 7 | % | | 27 | % | | 4 | % | | 2 | % | | 5 | % | | 12 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 59 | % | | 12 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 48 | % | | 6 | % | | 30 | % | | 2 | % | | 3 | % | | 11 | % | | — | % |
| Entergy Mississippi | 64 | % | | — | % | | 24 | % | | 10 | % | | 2 | % | | — | % | | — | % |
| Entergy New Orleans | 51 | % | | 1 | % | | 43 | % | | 1 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 43 | % | | 31 | % | | 17 | % | | 6 | % | | 3 | % | | — | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 45 | % | | 6 | % | | 35 | % | | 6 | % | | 3 | % | | 5 | % | | — | % |
(a)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2023 is not projected for 2024.
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 2024, 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 70% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply at least 85% of the total coal supply needs in 2024. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2024. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2024.
Entergy Louisiana has committed to three two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2024. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2024. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2024.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units were able to fully meet supply needs and obligations in 2023. While deliveries remained constrained through summer 2023, improvements were observed in the second half of the year and are expected to continue in 2024. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2024, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners, including their ability to work through supply disruptions caused by global events, such as the COVID-19 pandemic, or national events, such as political disruption. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk factorsmanagement strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with one interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Symmetry Energy Solutions which ensures 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 2023 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction), as well as the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff is subject to change and has recently undergone significant changes. As an example, MISO recently has made changes to its capacity accreditation methodology for thermal resources which emphasize performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now pursuing a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources.
MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO’s functional control. This process generally involves parties that wish to interconnect new generation resources submitting to MISO requests to do so, which are then studied and analyzed by MISO, with the participation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO’s current tariff, these requests are studied and considered in clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue.
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.
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
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membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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 retail 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. 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. The remainder of Entergy Arkansas’s retained share is sold to Entergy Mississippi through a separate life-of-resource purchase power agreement with Entergy Mississippi. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy
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Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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 to System Energy have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement. See Note 8 to the financial statements for discussion of the Reallocation Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, pursuant to which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans
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assumed all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.
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, as well as to Entergy’s non-utility operations business. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations, and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other informationoperating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in this Form 10-K.Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
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
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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 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 riskstransaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Other Business Activities
Entergy’s non-utility operations business includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy’s non-utility operations
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business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy’s non-utility operations business owns interests in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy’s non-utility operations business. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
All generation owned by Entergy’s non-utility operations business falls under the authority of MISO. Customers for the sale of both energy and capacity from its owned generation and contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of the non-utility operations businesses’ owned generation and contracted power purchases are sold under a cost-based contract.
TLG Services, a subsidiary in Entergy’s non-utility operations business, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as 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.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity at or above 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities, certain transmission projects, and certain distribution projects with construction costs greater than $10 million;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2023 of $205.2 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing of the Yucca Mountain repository (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 is in partial breach of its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. Although the NRC completed the safety evaluation report for the license review in 2015, the previously appropriated funds are not limitedsufficient to complete the review, including required hearings. The government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.
Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear
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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 2021, 2022, and 2023 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE. Through 2023, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposed a reinstatement of decommissioning cost recovery for ANO 2. In December 2022 the APSC ordered reinstatement of decommissioning collections for ANO 2 in accordance with the request in the November 2022 filing. In November 2023, Entergy Arkansas filed a further revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust continued to be adequately funded, but that ANO 2’s fund continued to require collections higher than those in this section. Thereeffect. In December 2023 the APSC approved the proposed higher decommissioning collections for ANO 2.
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
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3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In October 2023 a procedural schedule was adopted that includes a hearing date in August 2024. Management cannot predict the outcome of these proceedings.
In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a base rate case that proposed continuation of the cessation of River Bend decommissioning collections. In May 2023, Entergy Texas filed on behalf of the parties to the base rate case an unopposed settlement, which included an agreement to maintain Entergy Texas’s decommissioning funding for River Bend at a revenue requirement of $0. In August 2023 the PUCT issued an order accepting the unopposed settlement, including the proposed decommissioning funding settlement terms.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. In March 2023 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $165.9 million per reactor (with 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to
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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, “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 with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently unknownin Column 1, except River Bend, which is in Column 2.
In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.
Environmental Regulation
Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted below. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not currently believedexpected to be material) that could adversely affect Entergy’s financial condition,have a material effect on their competitive position, results of operations, cash flows, or financial position.
Clean Air Act and liquidity.Subsequent Amendments
The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
•new source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;
•acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx);
•nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;
•hazardous air pollutant emissions reduction programs;
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•Interstate Air Transport;
•operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•new and existing source standards for greenhouse gas and other air emissions.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. In April 2023 the EPA issued a regulatory proposal to revise portions of the MATS rule, including a proposed reduction to the emission limit for filterable particulate matter. If finalized, the proposed lower filterable particulate matter emission limitation could require additional capital investment and/or additional other operation and maintenance costs at Entergy’s coal-fired generating units. Entergy is closely monitoring this rulemaking, in part through its various trade associations.
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Good Neighbor Plan/Cross-State Air Pollution Rule
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In June 2023 the EPA published its final Federal Implementation Plan (FIP), known as the Good Neighbor Plan, to address interstate transport for the 2015 ozone NAAQS which would increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Entergy is currently assessing its compliance options for the FIP. Prior to issuance of the FIP, in February 2023 the EPA issued related State Implementation Plan (SIP) disapprovals for many states, including the four states in which the Utility operating companies operate, and these SIP disapprovals are the subject of many legal challenges, including a petition for review filed by Entergy Louisiana challenging the disapproval of Louisiana’s SIP. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the Good Neighbor Plan will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2024. The final FIP also is subject to numerous legal challenges.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop 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.
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 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, NISCO, and Ninemile. Responses to the information collection requests were submitted to the respective state agencies. Louisiana issued its draft SIP which did not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The
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Mississippi Department of Environmental Quality also did not meet the July 31, 2021 SIP submission deadline and continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In 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.
Consistent with the Biden administration’s stated climate goals, in May 2023 the EPA proposed several rules regulating greenhouse gas emissions from new and existing coal and gas-fired power plants. If finalized, the proposed requirements for existing “large and frequently used” gas turbine generating units could require significant investments in CO2 emission reduction technologies at certain of Entergy’s existing gas turbine units with a capacity of greater than 300 MW per combustion turbine and which operate at an annual capacity factor of greater than 50 percent. Comments on the proposed rules were submitted in August 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “FORWARD-LOOKING INFORMATION.Risk Factors” in Part I, Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
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Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the regional cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs) and increased regulation of per- and polyfluorinated substances or other chemicals;
•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 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015
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definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was subject to multiple legal challenges and was enjoined from implementation or enforcement throughout Entergy’s utility service territory. In May 2023 the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and in September 2023 the EPA and the Corps issued a final rule incorporating the Supreme Court decision. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been 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 April 2015 the EPA published the final coal combustion residuals (CCR) rule regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes regulated under Resource Conservation and Recovery Act Subtitle D. The final regulations created new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria but excluded CCRs that are beneficially reused in certain processes. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed. As of December 31, 2023, Entergy has recorded asset retirement obligations related to CCR management of $28 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each 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 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.
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Additionally, all three sites are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines (ELG). The nature, cost, and timing of those compliance measures depends on the guidance included in the final ELG rule, which is expected by mid-2024.
In May 2023 the EPA released a proposed rule establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (i.e., non-containerized CCR located at a regulated CCR facility). Entergy does not have any legacy impoundments; however, the proposed definition of CCR management units appears to regulate on-site areas where CCR was beneficially used. This is contrary to the current CCR rule which exempts beneficial uses that meet certain criteria. Comments on the proposed rule were submitted in July 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
•The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System EnergyRegistrant Subsidiaries are determined through regulatory approval proceedings that can be lengthy and subject to appeal, that could resultpotentially resulting in delays in effecting rate changeslengthy litigation, and uncertainty as to ultimate results.
•Entergy’s business could experience adverse effects related to changes to state or federal legislation or regulation, or experience risks associated with participation in the MISO markets and allocation of transmission upgrade costs.
•The ratesUtility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
•A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material effects on Entergy and its Utility operating companies affected by severe weather.
•Weather, economic conditions, technological developments, and other factors may have a material impact on electricity and gas usage and otherwise materially affect the Utility operating companies’ results of operations.
Nuclear Operating, Shutdown, and Regulatory Risks
•The results of operations, financial condition, and liquidity of Entergy Arkansas, Entergy Louisiana, and System Energy could be materially affected by the following:
◦inability to consistently operate their nuclear power plants at high capacity factors;
◦refueling outages that last materially longer than anticipated or unplanned outages;
◦risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication);
◦the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants;
◦risks and costs related to operating and maintaining their nuclear power plants;
◦the costs associated with the storage of the spent nuclear fuel, as well as the costs of and their ability to fully decommission their nuclear power plants;
◦the potential requirement to pay substantial retrospective premiums and/or assessments imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance;
◦the risk that the decommissioning trust fund assets 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.
Business Risks
•Entergy and the Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints. Disruptions in the capital and credit markets or a downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could, among other things, adversely affect their ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
•The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet their stated goals or commitments, among other potential causes.
•Changes in tax legislation and taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
•Entergy and its subsidiaries’ ability to successfully execute on their business strategies, including their ability to complete capital projects, other capital improvements, and strategic transactions, is subject to significant risks, and, as a result, they may be unable to achieve some or all of the anticipated results of such strategies.
•Failure to attract, retain, and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
•Entergy and its subsidiaries, including the Utility operating companies and System Energy, charge reflectmay incur substantial costs (i) to fulfill their capital expenditures, operationsobligations related to environmental and other matters or (ii) related to reliability standards.
•Entergy could be negatively affected by the effects of climate change, including physical risks, such as increased frequency and intensity of hurricanes, availability of water, droughts, and other severe weather and wildfires, and transition risks, such as environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, or increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions.
•Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding of such benefit plans and result in increased benefit plan costs.
•The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
•Terrorist attacks and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ physical infrastructure or technology systems may adversely affect Entergy’s business and results of operations.
•Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
•Significant increases in commodity prices, other materials and supplies, and operation and maintenance costs, allowed ratesexpenses may adversely affect Entergy’s results of return, financing costs,operations, financial condition, and related costsliquidity.
•The effect of service. These rates significantly influence the financial condition,higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidityliquidity.
•System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds, which financing may not be available on terms acceptable to System Energy when required.
•As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
•The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 24,000 MW of electric generating capacity. Entergy delivers electricity to approximately 3 million Utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $12.1 billion in 2023 and had approximately 12,000 employees as of December 31, 2023.
Entergy operates primarily through a single reportable segment, Utility. The Utility 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 in portions of Louisiana. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Entergy completed its multi-year strategy to exit the merchant nuclear power business in 2022 and upon completion of all transition activities, effective January 1, 2023, Entergy Wholesale Commodities is no longer a reportable segment. See Note 13 to the financial statements for discussion of and financial information regarding Entergy’s business segments.
Strategy
Entergy’s strategy is to operate and grow its utility business through a customer-centric approach designed to understand and meet customer needs, creating value for all of its key stakeholders, including customers, communities, employees, and owners. As part of its strategy, Entergy invests significant capital to support customer growth and its customers’ growing demands for greater reliability, resilience, and clean energy, while remaining focused on affordability. Entergy manages risks by ensuring its Utility investments are customer-driven, the result of robust analysis, supported by broad stakeholder outreach and progressive regulatory constructs, and executed with disciplined project management. Further, Entergy continues to integrate key sustainability elements, including social responsibility and good governance, into every decision it makes.
Utility
The Utility 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. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Planned Sale of Gas Distribution Businesses” for discussion of the planned sale of the Entergy New Orleans and Entergy Louisiana gas distribution businesses. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The Utility has a diverse power generation portfolio, including increasingly carbon-free energy sources, which is consistent with Entergy’s strong support for the environment.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Customers
As of December 31, 2023, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| Entergy Arkansas | Portions of Arkansas | | 730 | | | 24 | | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,105 | | | 37 | | | 96 | | | 47 | |
| Entergy Mississippi | Portions of Mississippi | | 459 | | | 15 | | | | | |
| Entergy New Orleans | City of New Orleans | | 208 | | | 7 | | | 108 | | | 53 | |
| Entergy Texas | Portions of Texas | | 512 | | | 17 | | | | | |
| Total | | | 3,014 | | | 100 | | | 204 | | | 100 | |
Electric and Natural Gas Energy Sales
Electric Energy Sales
The total electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On August 23, 2023, Entergy reached a 2023 peak demand of 23,319 MWh, compared to the 2022 peak of 22,301 MWh recorded on June 24, 2022. Selected electric energy sales data for 2023 is shown in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (GWh) |
| Sales to retail customers | 22,481 | | | 57,681 | | | 12,854 | | | 5,696 | | | 21,146 | | | — | | | 119,858 | |
| Sales for resale: | | | | | | | | | | | | | |
| Affiliates | 2,218 | | | 4,406 | | | — | | | — | | | — | | | 10,574 | | | — | |
| Others | 5,777 | | | 1,534 | | | 4,598 | | | 2,818 | | | 462 | | | — | | | 15,189 | |
| Total | 30,476 | | | 63,621 | | | 17,452 | | | 8,514 | | | 21,608 | | | 10,574 | | | 135,047 | |
| Average use per residential customer (kWh) | 12,561 | | | 14,893 | | | 14,226 | | | 12,610 | | | 14,941 | | | — | | | 14,089 | |
(a)Includes the effect of intercompany eliminations.
The following table illustrates the Utility operating companies’ 2023 combined electric sales volume as a percentage of total electric sales volume, and 2023 combined electric revenues as a percentage of total 2023 electric revenue, each by customer class.
| | | | | | | | | | | | | | |
| Customer Class | | % of Sales Volume | | % of Revenue |
| Residential | | 26.9 | | 38.4 |
| Commercial | | 20.9 | | 25.3 |
| Industrial (a) | | 39.1 | | 26.8 |
| Governmental | | 1.8 | | 2.3 |
| Wholesale/Other | | 11.3 | | 7.2 |
(a)Major industrial customers are primarily in the petroleum refining and chemical industries.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Natural Gas Energy Sales
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 8,917,149 and 6,130,048 Mcf, respectively, of natural gas to retail customers in 2023. In 2023, 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 2023.
Following is data concerning Entergy New Orleans’s 2023 retail operating revenue sources:
| | | | | | | | | | | | | | |
| Customer Class | | % of Electric Operating Revenue | | % of Natural Gas Operating Revenue |
| Residential | | 48 | | 51 |
| Commercial | | 35 | | 26 |
| Industrial | | 5 | | 17 |
| Governmental/Municipal | | 12 | | 6 |
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 and System Energy. These ratesEnergy’s retail rate mechanisms are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiativediscussed below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy Arkansas | | $10.1 (a) | | 9.15% - 10.15% | | 5.62% | | 38.7% (b) | | - forward test year formula rate plan - riders: fuel and purchased power, MISO, capacity, Grand Gulf, energy efficiency |
| Entergy Louisiana (electric) | | $15.7 (c) | | 9.0% - 10.0% | | 6.66% | | 49.51% | | - formula rate plan through 2022 test year - riders/specific recovery: MISO, capacity, transmission, fuel, distribution, tax reform |
| Entergy Louisiana (gas) | | $0.15 (d) | | 9.3% - 10.3% | | 6.93% | | 51.83% | | - gas rate stabilization plan - rider: gas infrastructure |
| Entergy Mississippi | | $4.2 (e) | | 9.74% - 11.88% | | 7.06% | | 46.76% | | - formula rate plan with forward-looking features - riders: fuel, Grand Gulf, MISO, unit power cost, storm damage, ad valorem tax adjustment, vegetation, grid modernization, restructuring credit, power management |
Part I Item 1
In addition, regulators may initiate proceedings to investigate the prudence of costs in the Utility operating companies’ 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 theEntergy Corporation, Utility operating companies, and System Energy to experience regulatory lag
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Rate base (in billions) | | Current authorized return on common equity | | Weighted-average cost of capital (after-tax) | | Equity ratio | | Regulatory construct |
| Entergy New Orleans (electric) | | $1.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - riders/specific recovery: fuel and purchased power, MISO, energy efficiency, environmental, capacity costs |
| Entergy New Orleans (gas) | | $0.2 (f) | | 8.85% - 9.85% | | 6.86% | | 51% (g) | | - formula rate plan with forward-looking features - rider: purchased gas |
| Entergy Texas | | $4.4 (h) | | 9.57% | | 6.61% | | 51.2% | | - rate case and cost recovery riders - riders: fuel, capacity, cost recovery riders (distribution, transmission, and generation), rate case expenses, advanced metering infrastructure surcharge, and tax reform, among others |
| System Energy | | $1.74 (i) | | 10.94% (j) | | 8.54% | | 59.5% (j) | | - monthly cost of service |
(a)Based on 2024 test year.
(b)Based on $1.9 billion in recovering costsaccumulated deferred income taxes at a 0% cost rate included in the weighted-average cost of capital calculation.
(c)Based on December 31, 2022 test year and excludes approximately $300 million of transmission plant investment included in the transmission recovery mechanism and approximately $200 million of distribution plant investment included in the distribution recovery mechanism, as well as approximately $400 million of net accumulated deferred tax liability items included in the tax reform adjustment mechanism.
(d)Based on September 30, 2022 test year.
(e)Based on 2023 forward test year.
(f)Based on December 31, 2022 test year and known and measurables through rates. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. December 31, 2023.
The base rates(g)In October 2023 the City Council approved a three-year extension of Entergy Texas are established largely in traditionalNew Orleans’s formula rate plan, modified to reflect a 55% fixed capital structure for rate setting purposes.
(h)Based on December 31, 2021 test year.
(i)Based on calculation as of December 31, 2023.
(j)Effective July 2022, Entergy Mississippi’s bills from System Energy reflect an authorized return on equity of 9.65%, a capital structure not to exceed 52% equity, and a rate base rate case proceedings. Apart from base rate proceedings, Entergy Texas has also filed to use rate riders to recover the revenue requirements associated with certain authorized historical costs. For example, Entergy Texas has recovered distribution-related capital investments through the distribution cost recovery factor rider mechanism, transmission-related capital investments and certain non-fuel MISO charges through the transmission cost recovery factor rider mechanism, and MISO fuel and energy-related costs through the fixed fuel factor mechanism. Entergy Texas is also required to make a filing every three years, at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contractsreduction for the reconciliation period.advance collection of sale-leaseback rental costs. See Note 2 to the financial statements for discussion of ongoing proceedings at the FERC challenging System Energy’s authorized return on common equity and capital structure.
Entergy Arkansas
Formula Rate Plan
Between base rate cases, Entergy Arkansas and Entergy Mississippi areis 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 (Entergy Arkansas) or forward-looking features (Entergy Mississippi).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
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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 expiresexpired in 2021 unless2021. As granted by Arkansas law, Entergy Arkansas requests, and theobtained APSC approves,approval of the extension of the formula rate plan tariff for an additional five yearsfive-year term, through 2026. InAs part of the event thatsettlement of the 2023 formula rate plan proceeding, Entergy Arkansas agreed to file its next base rate case no later than February 2026. If Entergy Arkansas’s formula rate plan iswere terminated, or is not extended beyond the initial term, Entergy Arkansas could file an
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism. If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan. Entergy Arkansas
Fuel and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.Purchased Power Cost Recovery
Entergy Louisiana historically sets electric base rates annually through a formulaArkansas’s rate plan usingschedules include an historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan was approved for continued use through the test year 2016 filing and included a cap inenergy cost of service increases at a cumulative total of $30 million through the formula rate plan cycle, which cap was not reached. The LPSC also approved in the business combination Entergy Louisiana’s continuation of a mechanism to recover non-fuel MISO-related costs, which are calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. This recovery mechanism expired following the 2015 test year, but was renewed for the 2016 test year. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. The formula rate plan includes exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities, as well as purchase power agreements approved by the LPSC, among other items. In August 2017, Entergy Louisiana filed to extend the formula rate plan for an additional three years and to reset rates to the authorized mid-point return on equity of 9.95%. The filing also seeks certain modifications to the formula rate plan, including a narrower, 80 basis points earnings sharing bandwidth and implementation of a rider to recover certain transmission-related investments, when those investments begin delivering benefits to customers. In the event that the electric formula rate plan is not renewed or extended, Entergy Louisiana would revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year. Currently, based on a settlement agreement approved by the City Council, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. The limited exceptions include implementation of the final year of a four-year phased-in rate increase for its Algiers operations in the Fifteenth Ward of the City of New Orleans and certain exceptional cost increases or decreases in its base revenue requirement.
The rates of System Energy are established by the FERC, and the costs allowed to be charged pursuant to these rates are, in turn, passed through to the participating Utility operating companies through the Unit Power Sales Agreement, which allows monthly adjustments to reflect the current operating costs of, and investment in, Grand Gulf.
The 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. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
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, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs. Regulators may also initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for recovery atthe twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a later date, which could increasetrue-up adjustment reflecting 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.
There remains uncertainty regarding the effectover-recovery or under-recovery, including carrying charges, of the termination of the System Agreement on the Utility operating companies.
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC. The System Agreement terminated in its entirety on August 31, 2016.
There remains uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it had been in existence. In the absence of the System Agreement, there remains uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement terminated in its entirety in August 2016, there are a number of outstanding System Agreement proceedings at the FERC that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their 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 power in certain regions and/or the economic value of such sales, and MISO market rules may change in ways that cause additional risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. MISO is currently evaluating through its stakeholder process potential changes in the transmission project criteria in MISO. These changes, if adopted, could potentially result in a larger
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
volume of competitively bid and regionally cost allocated transmission projects. In addition to the cash and financing-related risks arising from the potential additional cost allocation to the Utility operating companies from these 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 and the allocation of transmission upgrade costs, 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 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 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.
(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 could have material effects on Entergy and those Utility operating companies affected by severe weather.
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.
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, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors, consistent with safety requirements. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additionalprior calendar year. The energy sometimes at higher costs, from their fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts cancost recovery rider tariff also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk, capped through the use of risk management products.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months and average approximately 30 days in duration. Plant maintenance and upgrades are often scheduled during such planned outages. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease and maintenance costs may increase. Lower than forecasted capacity factors may cause Entergy Wholesale Commodities to experience reduced revenues and may also create damages risk with certain hedge products as previously discussed.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication). These risks could materially affect Entergy’s and their results of operations, financial condition and liquidity.
Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2018. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdown of the Palisades, Pilgrim, Indian Point 2 and Indian Point 3 plants over the next two to five years. 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. 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, System Energy, and Entergy Wholesale Commodities.
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 countries, such as Russia, in which deteriorating economic conditions or international sanctions could restrict the ability of such suppliers to continue to supply fuel or provide such services. 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, System Energy, and Entergy Wholesale Commodities.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend, not renew, 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, not renew, 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
nuclear facilities. The license renewal process in some cases may be the subject of significant public debate and legislative review and scrutiny at the federal and, in some cases, state level, though the decision whether to renew is subject to the exclusive jurisdiction of the NRC. 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 and Note 8 to the financial statements.
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, ifallows 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. 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. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to the effects of stress corrosion cracking and other corrosion mechanisms on certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished. In addition, certain major parts have long lead-times to manufacture
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 owners of the Entergy Wholesale Commodities nuclear plants incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or 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 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. 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 of up to approximately $127.3 million per reactor. With 102 reactors currently participating, this translates to a total public liability cap of approximately $13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As 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 as of January 1, 2018). Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool. 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 Entergy Wholesale Commodities plant owners, 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 $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.146 billion). The retrospective premium payment is currently limited to approximately $19 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $127.3 million cap.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities plants. 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 surplus (reserve) be significantly depleted due toinsured losses. As of December 31, 2017, the maximum annual assessment amounts total $112.2 million for the Utility plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.
As 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 owners of the Entergy Wholesale Commodities nuclear power plants 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.
In connection with the acquisition of certain nuclear plants, the Entergy Wholesale Commodities plant owners acquired decommissioning trust funds that are funded in accordance with NRC regulations. Under NRC regulations, Entergy Wholesale Commodities’ nuclear subsidiaries 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 of the Entergy Wholesale Commodities nuclear power plant’s decommissioning trusts combined with 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, for each of these nuclear power plants. As a result, if the projected amount of individual plants’ decommissioning trusts exceeds the NRC-required decommissioning amount, then its decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs the applicable Entergy subsidiaries would be required to incur 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 would be required. Furthermore,request depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
Further, federalover- 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,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
or accelerate the timing for funding of, the obligations related to the decommissioning of Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. 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 Entergy Wholesale Commodities nuclear plant owners may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to 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 and the impairment charges that resulted from such decision, see the “Critical Accounting Estimates- Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy, the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and Notes 9 and 14 to the financial statements.
Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.
NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants. Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies’, System Energy’s, and owners of Entergy Wholesale Commodities nuclear power plants. Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. For further information regarding nuclear decommissioning costs, 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 and Note 9 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, in particular in the northeastern United States, which is where most of the current fleet of Entergy Wholesale Commodities nuclear power plants is located. These concerns have led to, and are expected to 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 could lead to the shutdown of nuclear units, denial of license renewal applications, 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, financial condition, and liquidity.
(Entergy Corporation)
A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities’ Indian Point nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an acceleration of the timing for the funding of decommissioning obligations.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The license renewal and related processes for the Entergy Wholesale Commodities’ Indian Point nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The original expiration date of the operating license for Indian Point 2 was September 2013 and the original expiration date of the operating license for Indian Point 3 was December 2015. Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined.
In January 2017, Entergy announced that it plans to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021. The early and orderly shutdown is part of a settlement under which New York State has agreed to drop legal challenges and support renewal of the operating licenses for Indian Point. For additional discussion of the settlement agreement with New York State, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
If the NRC were to deny the applications for the renewal of operating licenses for the Indian Point nuclear power plants, or if Indian Point fails to obtain other approvals, Entergy’s results of operations, financial condition, and liquidity could be materially affected by loss of revenue and cash flow associated with the plant or plants until the proposed shutdown date, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal. For further discussion regarding the license renewal processes for the Indian Point nuclear power plants, see the “Entergy Wholesale Commodities Authorizations to Operate Indian Point” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. As a result, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2017, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 98% in 2018, 91% in 2019, 51% in 2020, 74% in 2021, and 67% in 2022 of its generation portfolio’s planned energy output, reflecting the planned shutdown or sale of the Entergy Wholesale Commodities nuclear power plants by mid-2022.
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules and other mechanisms to address volatility and other issues in these markets.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses (or requested operating licenses for Indian Point 2 and Indian Point 3).
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.
Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy’s control to a significant degree, are:
prevailing market prices for natural gas, uranium (and its conversion, enrichment, and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;
seasonality and realized weather deviations compared to normalized weather forecasts;
availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;
changes in production and storage levels of natural gas, lignite, coal and crude oil, and refined products;
liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term;
the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;
electricity transmission, competing generation or fuel transportation constraints, inoperability, or inefficiencies;
the general demand for electricity, which may be significantly affected by national and regional economic conditions;
weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;
the rate of growth in demand for electricity as a result of population changes, regional economic conditions, and the implementation of conservation programs or distributed generation;
regulatory policies of state agencies that affect the willingness of Entergy Wholesale Commodities customers to enter into long-term contracts generally, and contracts for energy in particular;
increases in supplies due to actions of current Entergy Wholesale Commodities competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities, and improvements in transmission that allow additional supply to reach Entergy Wholesale Commodities’ nuclear markets;
union and labor relations;
changes in Federal and state energy and environmental laws and regulations and other initiatives, such as the Regional Greenhouse Gas Initiative, including but not limited to, the price impacts of proposed emission controls;
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; and
natural disasters, terrorist actions, wars, embargoes, and other catastrophic events.
The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Entergy Wholesale Commodities business is subject to extensive regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets may impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. Further, the New York Independent System Operator could determine that the timing of the shutdown of the Indian Point units could be inconsistent with its market power rules, and impose certain penalties that could affect Entergy Wholesale Commodities. 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. In particular, the assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure or sale of the plants discussed below. Moreover, prior to the closure or sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit (including if the operating licenses for the Indian Point power plants are not renewed by the NRC), or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. Vermont Yankee ceased power production in the fourth quarter 2014 at the end of a fuel cycle. This decision was approved by the Board in August 2013, and resulted in the recognition of impairment charges in 2013 and 2014. In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick was expected to shut down at the end of its current fuel cycle, planned for January 27, 2017, but in March 2017, Entergy sold the FitzPatrick plant to Exelon Generation Company, LLC which continues to operate the plant. During the third quarter 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In addition, in the fourth quarter 2015, Entergy recorded impairment and other related charges to write down the carrying value of the Palisades plant and related assets to their fair value. In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant and to shut down the plant in 2018, but the agreement was terminated in September 2017 after the Michigan Public Service Commission decided that Consumers Power could not recover costs incurred under the agreement. Entergy intends to shut down the Palisades plant permanently on May 31, 2022. In January 2017, Entergy announced that it reached a settlement with New York State and plans to close the Indian Point 2 plant in 2020 and the Indian Point 3 plant in 2021. As a result, in the fourth quarter of 2016, Entergy recorded impairment and other related charges to write down the carrying values of the Palisades and Indian Point 2 and Indian Point 3 plants and related assets to their fair value. In addition to the impairments and other related charges, Entergy has incurred severance and employee retention costs and expects to incur additional charges through 2022 relating to the decisions to shut down Vermont Yankee, Palisades, Pilgrim, Indian Point 2 and Indian Point 3, and the sale of FitzPatrick.
If Entergy concludes that any of its nuclear power plants is unlikely to operate through its planned shutdown date, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets and Trust Fund Investments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
Part I Item 1A & 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, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, higher than expected pension contributions, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, 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 uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Events beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. 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 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Most of Entergy Corporation’s and its subsidiaries’ large customers, 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, 2017, based on power prices at that time, Entergy had liquidity exposure of $167 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, 2017, Entergy would have been required to provide approximately $98 million of additional cash or letters of credit under some of the agreements. In the event of a decrease in the credit ratings of Entergy’s Utility operating companies to below investment grade, those companies collectively could be required to provide up to $50 million of additional cash or letters of credit to MISO. As of December 31, 2017, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously received collateral from counterparties, would increase by $372 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, cash flows, and credit ratings.
The recently enacted H.R. 1, also known as the Tax Cuts and Jobs Act of 2017, will significantly change the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The legislation is unclear in certain respects and will require interpretations and implementing regulations by the IRS, as well as state tax authorities, and the legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain impacts of the legislation. In addition, the regulatory treatment of the impacts of this legislation, particularly on companies like Entergy and the Registrant Subsidiaries, will be subject to the discretion of federal, state, and local public utility regulators.
As further described in Note 3 to the financial statements, Entergy recorded a reduction of certain of its net deferred income tax assets (including the value of its net operating loss carryforwards) and regulatory liabilities, resulting in a charge against earnings in the fourth quarter 2017 of $526 million, including a $34 million net-of-tax reduction of regulatory liabilities, and Entergy and the Utility operating companies recorded a reduction of approximately $3.7 billion on a consolidated basis in certain of its net deferred tax liabilities and a corresponding increase in net regulatory liabilities. Depending on the outcome of the ratemaking process, IRS examinations, or tax positions and elections that Entergy may elect, Entergy and the Registrant Subsidiaries may be required to record additional charges or credits to income tax expense. Further, the amount and timing of the return of the deferred taxes to customers is dependent upon the regulatory treatment received, and, if the Registrant Subsidiaries are unsuccessful in receiving balanced regulatory treatment, Entergy’s or the Utility operating companies’ cash flow could be materially adversely affected. Further, there may be other material effects resulting from the legislation that have not been identified. While Entergy plans to finance its cash needs that result from the Act through a combination of Registrant Subsidiary debt and Entergy Corporation debt and equity, there can be no assurance that Entergy or the Registrant Subsidiaries will obtain debt or equity financing on terms that are satisfactory or consistent with their current expectations.
In addition, while Moody’s changed the ratings outlooks for Entergy Corporation to negative from stable in reaction to the legislation, it is unclear when or how capital markets, other credit rating agencies, the FERC or state or local regulators may respond to this legislation. Entergy expects that certain financial metrics used by credit rating agencies will be negatively affected as a result of the return of excess deferred taxes to customers, increased debt, and the decrease in the Registrant Subsidiaries’ revenue requirements, and related decrease in operating cash flows, expected as a consequence of the lower federal corporate income tax rate while, at the same time, the loss of the bonus depreciation tax deduction will increase taxable income in the future. Also, the timing of the return of excess deferred income taxes
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
to customers will not exactly match the lower taxes that Entergy will be paying which will result in cash outflows to customers. It is also uncertain how other credit rating agencies will treat the impacts of this legislation on their credit ratings and metrics, and whether additional avenues will evolve for companies to manage the adverse aspects of this legislation. These avenues, to the extent available and if successfully applied, could lessen the impacts on certain credit metrics, although there can be no assurance in this regard.
Entergy believes that interpretations and implementing regulations by the IRS, as well as potential amendments and technical corrections, could result in lessening the impacts of certain aspects of this legislation. If Entergy is unable to successfully pursue avenues to manage the effects of the new tax legislation, or if additional interpretations, regulations, amendments, or technical corrections exacerbate the effects of the legislation, the legislation could have a material effect on Entergy’s results of operations, financial condition, and cash flows, and could result in additional credit rating agency actions. Any such actions by credit rating agencies may make it more difficult and costly for Entergy to issue debt securities and certain other types of financing and could increase borrowing costs under its credit facilities.
For further information regarding the effects of the Act, see the “Income Tax Legislation” section of Management’s Financial Discussion and Analysis for Entergy. Also, Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the 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 further information regarding Entergy’s income taxes, see Note 3 to the financial statements.
Entergy and its subsidiaries’ ability to successfully complete strategic transactions, including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions, is subject to significant risks, including the risk that required regulatory or governmental approvals may not be obtained, risks relating to unknown or undisclosed problems or liabilities, and the risk that for these or other reasons, Entergy and its subsidiaries may be unable to achieve some or all of the benefits that they anticipate from such transactions.
From time to time, 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, in November 2016, Entergy announced that it had entered into a purchase and sale agreement with NorthStar for the sale of 100% of the membership interests in Entergy Nuclear Vermont Yankee, which owns the Vermont Yankee plant. In addition, as part of Entergy’s plan to exit the merchant power business, it plans to shut down its remaining merchant nuclear power plants by mid-2022. These transactions and plans are or may become subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions or plans or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s financial condition, 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:
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
the disposition of a business or asset may involve continued financial involvement in the divested business, such as through continuing equity ownership, transition service agreements, guarantees, indemnities, or other current or contingent financial obligations;
Entergy may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms in a timely manner when it decides to sell an asset or a business, which could delay the accomplishment of its strategic objectives. Alternatively, Entergy may dispose of a business or asset at a price or on terms that are less than what it had anticipated, or with the exclusion of assets that must be divested or run off separately;
the disposition of a business could result in impairments and related write-offs of the carrying values of the relevant assets;
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;
the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;
Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable to them, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy may not be successful in managing these or any other significant risks that it may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on its business.
The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement 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 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 and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the 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 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 the potential construction 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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 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 are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants are potentially subject to increased regulation, controls and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, 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, 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 North American Electric Reliability Corporation (NERC), the SERC Reliability Corporation (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. The changes to the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
The effects of weather and economic conditions, and the related impact on electricity and gas usage, may materially affect the Utility operating companies’ results of operations.
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, moderate temperatures in either season tend to decrease usage of energy and resulting revenues. Seasonal pricing differentials, coupled with higher consumption levels, typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions or storms, however, 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, and lower 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 economic conditions, weather, customer bill sizes (large bills tend to induce conservation), 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 demand from Entergy. 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 increasing adoption of energy efficient appliances, new building codes, distributed energy resources, energy storage, demand side management and new technologies such as rooftop solar are having a more permanent effect of reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may experience lower usage per customer in the residential and commercial classes, and further advances have the potential to limit sales growth in the future. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity prices; however, they are sensitive to changes in conditions in the markets in which its customers operate. Any negative change in any of these or other factors has the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or to place a price on greenhouse gas emissions 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, federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. In 2010, the EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units. During 2012 and 2014, the EPA proposed CO2 emission standards for new and existing sources. The EPA finalized these standards in 2015; however, in late 2017, the EPA proposed to repeal the regulations and issued an Advanced Notice of Proposed Rulemaking for replacing certain aspects of the standards for existing sources. 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
developed in California. The impact that recent changes in the federal government will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction requirements can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects; 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. 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 deny or defer timely recovery of these costs. Future changes in environmental regulation governing the emission of CO2 and other greenhouse gases could make some of Entergy’s electric generating units uneconomical to maintain or operate, and could increase the difficulty that Entergy and its subsidiaries have with obtaining or maintaining required environmental regulatory approvals, which could also materially affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In addition to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, 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 wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply 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, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Three of Entergy’s Utility operating companies 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.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, 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
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies operate, in particular Louisiana, Mississippi, and Texas, 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.
Domestic or international terrorist attacks, including cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ technology systems may adversely affect Entergy’s results of operations.
As power generators and distributors, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, including physical and cyber attacks, either as a direct act against one of Entergy’s generation facilities, transmission operations centers, or distribution infrastructure used to manage and transport power to customers. 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 its business. While malware was recently discovered on our corporate network and remediated on a timely basis, it did not affect the company’s operational systems, nuclear plants or transmission network, nor did it have a material effect on our operations. Additionally, within Entergy’s industry, there have been attacks on energy infrastructure, but with minimal impact to operations, and there may be more attacks in the future. The Utility operating companies also face heightened risk of an act or threat by cyber criminals intent on accessing personal information for the purpose of committing identity theft, taking company-sensitive data, or disrupting the company’s ability to operate.
Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure in accordance with mandatory and prescriptive standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries,
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
technology systems remain vulnerable to potential threats that could lead to unauthorized access or loss of availability to critical systems essential to the reliable operation of Entergy’s electric system. Moreover, the functionality of Entergy’s technology systems depends on both its and third-party systems to which Entergy is connected directly or indirectly (such as systems belonging to suppliers, vendors and contractors). While Entergy has processes in place to assess systems of certain of these suppliers, vendors and contractors, Entergy does not ultimately control the adequacy of their defenses against cyber and other attacks, but has implemented oversight measures to assess maturity and manage third-party risk. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to detect or recover in a timely fashion to a normal state of operations, Entergy or its subsidiaries may be unable to perform critical business functions that are essential to the company’s well-being and the health, safety, and security needs of its customers. In addition, an attack on its information technology infrastructure may result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, vendors, and others in Entergy’s care.
Any such attacks, failures or breaches could have a material effect on Entergy’s and the Utility operating companies’ business, financial condition, results of operations or reputation. Insurance may not be adequate to cover losses that might arise in connection with these events. The risk of such attacks, failures, or breaches may cause Entergy and the Utility operating companies to incur increased capital and operating costs to implement increased security for its power generation, transmission, and distribution assets and other facilities, such as additional physical facility security and security personnel, and for systems to protect its information technology and network infrastructure systems. Such events may also expose Entergy to an increased risk of litigation (and associated damages and fines).
(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 are affected by the amount of gas sold to customers. 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. When purchased gas cost charges increase substantially reflecting higher gas procurement costs incurred by Entergy New Orleans, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations.
(System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on affiliated companies for all of its revenues.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as 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 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.
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 (including the Capital Funds
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Agreement), see Notes 8 and 10 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 payments of dividends or distributions to Entergy Corporation by its subsidiaries in turn depend 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. Provisions in the articles of incorporation of certain of Entergy Corporation’s subsidiaries restrict the payment of cash dividends to Entergy Corporation. For further information regarding dividend or distribution restrictions to Entergy Corporation, see Note 7 to the financial statements.
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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2017 Compared to 2016
Net income decreased $27.4 million primarily due to higher nuclear refueling outage expenses, higher depreciation and amortization expenses, higher taxes other than income taxes, and higher interest expense, partially offset by higher other income.
2016 Compared to 2015
Net income increased $92.9 million primarily due to higher net revenue and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate and higher depreciation and amortization expenses.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2017 to 2016.
|
| | | |
| Amount |
| (In Millions) |
| |
2016 net revenue |
| $1,520.5 |
|
Retail electric price | 33.8 |
|
Opportunity sales | 5.6 |
|
Asset retirement obligation | (14.8 | ) |
Volume/weather | (29.0 | ) |
Other | 6.5 |
|
2017 net revenue |
| $1,522.6 |
|
The retail electric price variance is primarily due to the implementation of formula rate plan rates effective with the first billing cycle of January 2017 and an increase in base rates effective February 24, 2016, each as approved by the APSC. A significant portion of the base rate increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016. The increase was partially offset by decreases in the energy efficiency rider, as approved by the APSC, effective April 2016 and January 2017. See Note 2 to the financial statements for further discussion of the rate case and formula rate plan filings. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
The opportunity sales variance results from the estimated net revenue effect of the 2017 and 2016 FERC orders in the opportunity sales proceeding attributable to wholesale customers. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and decommissioning trust fund earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by a decrease in regulatory credits because of an increase in decommissioning trust fund earnings, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales during the billed and unbilled sales periods. The decrease was partially offset by an increase of 733 GWh, or 11%, in industrial usage primarily due to a new customer in the primary metals industry.
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
2015 net revenue |
| $1,362.2 |
|
Retail electric price | 161.5 |
|
Other | (3.2 | ) |
2016 net revenue |
| $1,520.5 |
|
The retail electric price variance is primarily due to an increase in base rates, as approved by the APSC. The new base rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase includes an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase was related to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 2 to the financial statements for further discussion of the rate case. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Other Income Statement Variances
2017 Compared to 2016
Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the most recent outages compared to previous outages.
Other operation and maintenance expenses increased primarily due to:
the deferral in the first quarter 2016 of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement;
an increase of $9.5 million in transmission and distribution expenses primarily due to higher vegetation maintenance costs and higher labor costs, including contract labor;
an increase of $5.9 million in compensation and benefits costs primarily due to higher incentive-based compensation accruals in 2017 as compared to the prior year; and
the effect of recording in July 2016 the final court decision in a lawsuit against the DOE related to spent nuclear fuel storage costs. The damages awarded included the reimbursement of $5.5 million of spent nuclear fuel
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for further discussion of Entergy Arkansas’s spent nuclear fuel litigation.
The increase was partially offset by:
a decrease of $16 million in nuclear generation expenses primarily due to a decrease in regulatory compliance costs compared to the prior year, partially offset by higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals. The decrease in regulatory compliance costs is primarily related to NRC inspection activities in 2016 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See Note 8 to the financial statements for a discussion of the ANO stator incident and subsequent NRC reviews;
a decrease of $11.5 million in energy efficiency expenses primarily due to the timing of recovery from customers; and
a decrease of $5.2 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs, partially offset by an overall higher scope of work including plant outages in 2017 compared to 2016.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes primarily due to higher assessments and higher millage rates and an increase in local franchise taxes primarily due to higher billing factors.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the Union Power Station purchased in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Other income increased primarily due to higher realized gains in 2017 compared to 2016 on the decommissioning trust fund investments, including portfolio rebalancing for the ANO 1 and ANO 2 decommissioning trust funds.
Interest expense increased primarily due to:
an increase of $3.3 million in estimated interest expense recorded in connection with the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and
the issuance in May 2017 of $220 million of 3.5% Series first mortgage bonds and the issuance in June 2016 of $55 million of 3.5% Series first mortgage bonds, partially offset by the redemption in July 2016 of $60 million of 6.38% Series first mortgage bonds and the redemption in February 2016 of $175 million of 5.66% Series first mortgage bonds. See Note 5 to the financial statements for further discussion of long-term debt.
2016 Compared to 2015
Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the most recent outages compared to previous outages.
Other operation and maintenance expenses decreased primarily due to:
a decrease of $21.6 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
the deferral of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and
a decrease of $7.2 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.
The decrease was partially offset by an increase of $24.1 million in nuclear generation expenses primarily due to an overall higher scope of work performed during plant outages and higher nuclear labor costs compared to prior year and an increase of $8.2 million in fossil-fueled generation expenses primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower residential and commercial revenues compared to the prior year and a decrease in payroll taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the Union Power Station purchased in March 2016. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Interest expense increased primarily due to:
$5.1 million in estimated interest expense recorded in connection with the FERC orders issued in April 2016 in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and
the net issuance of $230 million of first mortgage bonds in 2016. See Note 5 to the financial statements for further discussion of long-term debt.
Income Taxes
The effective income tax rates for 2017, 2016, and 2015 were 40.1%, 39.2%, and 35.3%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Income Tax Legislation
See the “Income Tax Legislation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cuts and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $20,509 |
| |
| $9,135 |
| |
| $218,505 |
|
| | | | | | |
| Net cash provided by (used in): | | | |
| | |
|
| Operating activities | 555,556 |
| | 676,511 |
| | 474,890 |
|
| Investing activities | (829,312 | ) | | (947,995 | ) | | (685,274 | ) |
| Financing activities | 259,463 |
| | 282,858 |
| | 1,014 |
|
| Net increase (decrease) in cash and cash equivalents | (14,293 | ) | | 11,374 |
| | (209,370 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $6,216 |
| |
| $20,509 |
| |
| $9,135 |
|
Operating Activities
Net cash flow provided by operating activities decreased $121 million in 2017 primarily due to income tax refunds of $8.1 million in 2017 compared to income tax refunds of $135.7 million in 2016. Entergy Arkansas had income tax refunds in 2016 and 2017 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Arkansas’s net operating losses. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audit.
Net cash flow provided by operating activities increased $201.6 million in 2016 primarily due to:
income tax refunds of $135.7 million in 2016 compared to income tax payments of $103.3 million in 2015. Entergy Arkansas had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for further discussion of the income tax audits;
the timing of payments to vendors; and
an increase in net revenue.
The increase was partially offset by a decrease due to the timing of recoveryunder-recovery of fuel and purchased powerenergy costs.
Investing Activities
Net cash flow used in investing activities decreased $118.7 million in 2017 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million and a decrease of $35.5 million in transmission construction expenditures primarily due to a lower scope of work performed in 2017. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The decrease was partially offset by:
an increase of $50.4 million in nuclear construction expenditures primarily due to a higher scope of work performed on various nuclear projects in 2017;
an increase of $37.7 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;
an increase of $32.9 million in information technology construction expenditures primarily due to increased spending on substation technology upgrades;
an increase of $22.3 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed on various projects in 2017; and
an increase of $11.2 million due to increased spending on advanced metering infrastructure.
Net cash flow used in investing activities increased $262.7 million in 2016 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million. See Note 14 to the financial statements for further discussion of the Union Power Station purchase. The increase was partially offset by fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle.
Financing Activities
Net cash flow provided by financing activities decreased $23.4 million in 2017 primarily due to:
a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station;
the net issuance of $119.1 million of long-term debt in 2017 compared to the net issuance of $189.1 million of long-term debt in 2016; and
$15 million in common stock dividends paid in 2017 resulting from Entergy Arkansas’s routine evaluation of its ability to pay dividends. There were no common stock dividends paid in 2016 in anticipation of the purchase of Power Block 2 of the Union Power Station.
The decrease was partially offset by:
money pool activity;
the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016; and
net short-term borrowings of $50 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2017 compared to net repayments of $11.7 million in 2016.
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 $114.9 million in 2017 compared to decreasing by $1.5 million in 2016. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash flow provided by financing activities increased $281.8 million in 2016 primarily due to:
the net issuance of $189.1 million of long-term debt in 2016 compared to the net retirement of $13.2 million of long-term debt in 2015;
a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station; and
net repayments of $11.7 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2016 compared to net repayments of $36.3 million in 2015.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by the redemptions of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock in 2016 and money pool activity.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $1.5 million in 2016 compared to increasing by $52.7 million in 2015.
See Note 5 to the financial statements for further details of long-term debt.
Capital Structure
Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table.
|
| | | |
| | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 55.5% | | 55.3% |
| Effect of excluding the securitization bonds | (0.3%) | | (0.4%) |
| Debt to capital, excluding securitization bonds (a) | 55.2% | | 54.9% |
| Effect of subtracting cash | —% | | (0.2%) |
| Net debt to net capital, excluding securitization bonds (a) | 55.2% | | 54.7% |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds are non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Arkansas may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 |
| | (In Millions) |
| Planned construction and capital investment: | | | |
| | |
|
| Generation |
| $190 |
| |
| $240 |
| |
| $225 |
|
| Transmission | 170 |
| | 165 |
| | 175 |
|
| Distribution | 225 |
| | 245 |
| | 225 |
|
| Utility Support | 110 |
| | 85 |
| | 85 |
|
| Total |
| $695 |
| |
| $735 |
| |
| $710 |
|
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019-2020 | | 2021-2022 | | after 2022 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $125 |
| |
| $266 |
| |
| $672 |
| |
| $4,208 |
| |
| $5,271 |
|
| Operating leases |
| $17 |
| |
| $29 |
| |
| $16 |
| |
| $24 |
| |
| $86 |
|
| Purchase obligations (b) |
| $595 |
| |
| $1,050 |
| |
| $863 |
| |
| $5,369 |
| |
| $7,877 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $64.1 million to its qualified pension plans and approximately $472 thousand to its other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has ($117.7) million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments, such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; resource planning, including potential generation projects; system improvements; investments in ANO 1 and 2; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As discussed above in “Capital Structure,” Entergy Arkansas routinely evaluates its ability to pay dividends to Entergy Corporation from its earnings. Provisions in Entergy Arkansas’s articles of incorporation relating to preferred
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.
Advanced Metering Infrastructure (AMI)
In September 2016, Entergy Arkansas filed an application seeking a finding from the APSC that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing included an estimate of implementation costs for AMI of $208 million. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $406 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value of existing meters, which was approximately $57 million at December 31, 2015, that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Deployment of the communications network is expected to begin in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings, and the 2018 costs were approved in the 2017 formula rate plan filing. In June 2017 the APSC staff and Arkansas Attorney General filed direct testimony. The APSC staff generally supported Entergy Arkansas’s AMI deployment conditioned on various recommendations. The Arkansas Attorney General’s consultant primarily recommended denial of Entergy Arkansas’s application but alternatively suggested recommendations in the event the APSC approves Entergy Arkansas’s proposal. Entergy Arkansas filed rebuttal testimony in June 2017, substantially accepting the APSC staff’s recommendations. In August 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement. In October 20172007 the APSC issued an order findingstating that Entergy Arkansas’s AMI deployment isenergy cost recovery rider will remain in effect, and any future termination of the public interest and approving the settlement agreementrider would be subject to a minor modification. Entergy Arkansas expects to recover the undepreciated balance of its existing meters through a regulatory asset to be amortized over 15 years. Entergy Arkansas has begun discussions with the other parties to implement the items in the settlement agreement including pre-pay and time of use programs.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| ($166,137) | | ($51,232) | | ($52,742) | | $2,218 |
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 August 2022. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2018. The $150 million credit facility permits the issuance of letters of credit against $5 million of the borrowing capacity of the facility. As of December 31, 2017, 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, 2017, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for further discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in May 2019. As of December 31, 2017, $50 million in letters of credit to support a like amount of commercial paper issued and $24.9 million in loans were outstanding under the Entergy Arkansas nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorizations from the FERC through October 2019 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 authorizedeighteen months advance notice by the APSC, and the current authorization extends through December 2018.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2015 Base Rate Filing
In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In September 2015 the APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. A settlement hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.
2016 Formula Rate Plan Filing
In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017. In April 2017, Entergy Arkansas filed a motion consented to by all parties requesting that it be permitted to submit the supplemental information requested by the APSC in conjunction with its 2017 formula rate plan filing, which was subsequently made in July 2017 and is discussed below. In May 2017 the APSC approved the joint motion and proposal to review Entergy Arkansas’s supplemental information on a concurrent schedule with the 2017 formula rate plan filing. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and recovery of the 2017 and 2018 nuclear costs.
2017 Formula Rate Plan Filing
In July 2017, Entergy Arkansas filed with the APSC its 2017 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2018 test period to be below the formula rate plan bandwidth. The filing projected a $129.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. Entergy Arkansas’s formula rate plan is subject to a four percent annual revenue constraint and the projected annual revenue requirement increase exceeded the four percent, resulting in a proposed increase for the 2017 formula rate plan of $70.9 million. In October 2017, Entergy Arkansas filed with the APSC revised formula rate plan attachments that projected a $126.2 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors. The revised formula rate plan filing included a proposed $71.1 million revenue requirement increase based on a revision to the four percent constraint calculation. In October 2017, Entergy Arkansas and the parties to the proceeding filed a joint motion to approve a unanimous settlement agreement resolving all issues in the docket and providing for recovery of the 2017 and 2018 nuclear costs. In December 2017 the APSC approved the settlement agreement and the $71.1 million revenue requirement increase, as well as Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2018.
Internal Restructuring
In November 2017, Entergy Arkansas filed an application with the APSC seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy Arkansas to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory reviewoccur following notice and approval by the APSC, the FERC, and the NRC. Entergy Arkansas also filed a notice with the Missouri Public Service Commission in December 2017 out of an abundance of caution, althoughhearing.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas does not serve any retail customers in Missouri. If the APSC approves the restructuring by September 1, 2018, and the restructuring closes on or before December 1, 2018, Entergy Arkansas proposed in its application to credit retail customers $66 million over six years, beginning in 2019. In February 2018, Entergy Arkansas filed supplemental testimony reducing the proposed retail customer credits to $39.6 million over six years. If the APSC, the FERC, and the NRC approvals are obtained, Entergy Arkansas expects the restructuring will be consummated on or before December 1, 2018.
It is currently contemplated that Entergy Arkansas would undertake a multi-step restructuring, which would include the following:
Entergy Arkansas would redeem its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million, which includes call premiums, plus accumulated and unpaid dividends, if any.
Entergy Arkansas would convert from an Arkansas corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas will allocate 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 will assume substantially all of the liabilities of Entergy Arkansas, in a transaction regarded as a merger under the TXBOC. Entergy Arkansas will remain in existence and hold the membership interests in Entergy Arkansas Power.
Entergy Arkansas will contribute 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 will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy Arkansas will change its name to Entergy Utility Property, Inc., and Entergy Arkansas Power will then change its name to Entergy Arkansas, LLC.
Upon the completion of the restructuring, Entergy Arkansas, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy Arkansas. Entergy Arkansas may modify or supplement the steps to be taken to effectuate the restructuring.
Production Cost Allocation Rider
The APSC approved aEntergy Arkansas has in place an APSC-approved production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed inproceedings.
Other
In June 2022 the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase inAPSC approved Entergy Arkansas’s compliance tariff filing for a proposed green tariff designed to help participating customers meet their renewable and sustainability goals and to enhance economic development efforts in Arkansas. The APSC approved an initial offering of 100 MW of solar capacity to be made available under this tariff.
In June 2023 the APSC approved Entergy Arkansas’s Go ZERO tariff, which provides participating industrial and commercial customers the opportunity to chose from a number of clean energy options to help them achieve their sustainability goals.
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. In 2021 the LPSC approved a settlement extending the formula rate plan for test years 2020, 2021 and 2022; certain modifications were made in that extension, including a decrease to the allowed return on equity, narrowing of the earnings “dead band” around the mid-point allowed return on equity, elimination of sharing above and below the earnings “dead band,” and the addition of a distribution cost recovery mechanism. The formula rate plan continues to include exceptions from the rate cap and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities and purchase power agreements approved by the LPSC, certain transmission investments, and certain distribution investments, among other items. In August
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2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years, test years 2023-2025, which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study, with a 2024-2026 test year formula rate plan. The application complies with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-service/rate case. See Note 2 to the financial statements for a discussion of Entergy Louisiana’s application.
Fuel and Purchased Power Cost 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 balance becauserevenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Arkansas paysLouisiana’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 over seven months but collectsfor the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs fromincurred with fuel cost revenues billed to customers, over twelve months.including carrying charges.
Retail Rates - Gas
In Mayaccordance 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 Arkansas filed its annual redeterminationGulf 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 production cost allocationLPSC 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 $3investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension
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allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then-current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the
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return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider.
In 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.
In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the annual power management and grid modernization riders effective January 2023.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
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Other
In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule.
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. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.
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.
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 filings to recover storm-related costs.
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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 and Purchased Power Cost 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. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 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. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.
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 to be recovered through a purchased power capacity rider. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs. In 2023, the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through a purchased power capacity rider.
Transmission, Distribution, and Generation 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 permitted 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. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their
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distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Other
In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.
As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.
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
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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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Beginning in 2021, System Energy implemented billing protocols to provide retail balanceregulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric
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service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2024-2058.
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, 20132023 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,036 | | | 1,548 | | | 521 | | | 1,825 | | | 969 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,798 | | | 5,594 | | | 2,728 | | | 2,137 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,904 | | | 1,744 | | | 641 | | | — | | | 417 | | | — | | | 102 | |
| Entergy New Orleans | | 662 | | | 635 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,234 | | | 990 | | | 1,994 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,245 | | | — | | | — | | | 1,245 | | | — | | | — | | | — | |
| Total | | 23,879 | | | 10,511 | | | 5,884 | | | 5,207 | | | 1,975 | | | 73 | | | 229 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,775 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 $67.8 million System Agreement bandwidth remedy payment madeage and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in May 2014 as a resultthe addition of about 7,963 MW of new long-term resources and the deactivation of about 4,241 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 compliance filing pursuantUtility 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
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products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•Entergy Texas’s construction of the FERC’s February 2014 orders related993 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. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to the bandwidth payments/receiptsbe in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June - December 2005 period.2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In January 2015July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC’s approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the St. Jacques facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar
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facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
•Entergy Louisiana expects to start construction on the 49 MW Sterlington Solar project in the fourth quarter 2024, located in Sterlington, Louisiana. The facility is expected to achieve commercial operation in January 2026.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from a 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 and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a 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 and TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, executed a 10-year agreement to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
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•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
•In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
•In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC
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requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
•In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, 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 as early as June 2026.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. Entergy Louisiana selected a combination of PPA and build own transfer resources in March 2023 some of which have been executed and are noted above, and negotiation of definitive agreements for the remaining resources are in progress.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2023, and negotiation of definitive agreements are in progress for all resources.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including among others:
•In March 2016, Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) 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). The facility is located near El Dorado, Arkansas and has been in operation since July 2003;
•In October 2019, Entergy Mississippi’s acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The facility is located in Choctaw County and has been in operation since July 2003;
•In November 2020, Entergy Louisiana’s acquisition of 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. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
•In June 2021, Entergy Texas’s acquisition of 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. The facility has been in operation since January 2010; and
•In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC voted to approve this project and in September 2023, Entergy Louisiana reported
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to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. A procedural schedule has not yet been set.
In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering 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 recoverybriefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas’s proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A
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paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas’s rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC’s order.
In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the $3settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to the transmission system which operates at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined-cycle combustion turbine generators and reciprocating internal combustion engine generators that are fueled by natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that participate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include generating and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2023, 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, 2023, 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
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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 average fuel cost per kWh for the Utility operating companies and System Energy for the years 2021-2023 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2023 | | (Cents Per kWh) |
| Entergy Arkansas | | 1.98 | | | 0.50 | | | 3.09 | | | 1.98 | | | 11.57 | | | 0.77 | |
| Entergy Louisiana | | 2.34 | | | 0.60 | | | 3.22 | | | 10.38 | | | 3.76 | | | 2.50 | |
| Entergy Mississippi | | 2.21 | | | — | | | 2.82 | | | 0.03 | | | 5.86 | | | 1.84 | |
| Entergy New Orleans (c) | | 2.05 | | | — | | | — | | | 3.24 | | | — | | | 2.33 | |
| Entergy Texas | | 2.29 | | | — | | | 3.17 | | | 2.25 | | | 5.64 | | | 3.18 | |
| System Energy | | — | | | 0.68 | | | — | | | — | | | — | | | — | |
| Utility | | 2.25 | | | 0.58 | | | 3.06 | | | 6.14 | | | 4.03 | | | 2.61 | |
| | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $0.1 million under-recovered amountin 2023, $2.9 million in 2022, and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2023 and projected 2024 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | 1 | % | | 57 | % | | 9 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 47 | % | | 7 | % | | 20 | % | | 2 | % | | 2 | % | | 10 | % | | 12 | % |
| Entergy Mississippi | 63 | % | | 1 | % | | 23 | % | | 7 | % | | 1 | % | | — | % | | 5 | % |
| Entergy New Orleans | 55 | % | | 1 | % | | 36 | % | | 1 | % | | 2 | % | | 1 | % | | 4 | % |
| Entergy Texas | 32 | % | | 25 | % | | 6 | % | | 3 | % | | — | % | | 4 | % | | 30 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 43 | % | | 7 | % | | 27 | % | | 4 | % | | 2 | % | | 5 | % | | 12 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 59 | % | | 12 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 48 | % | | 6 | % | | 30 | % | | 2 | % | | 3 | % | | 11 | % | | — | % |
| Entergy Mississippi | 64 | % | | — | % | | 24 | % | | 10 | % | | 2 | % | | — | % | | — | % |
| Entergy New Orleans | 51 | % | | 1 | % | | 43 | % | | 1 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 43 | % | | 31 | % | | 17 | % | | 6 | % | | 3 | % | | — | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 45 | % | | 6 | % | | 35 | % | | 6 | % | | 3 | % | | 5 | % | | — | % |
(a)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2023 is not projected for 2024.
Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the true-upUtility does not expect fuel oil use in 2024, 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 70% of the productionUtility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply at least 85% of the total coal supply needs in 2024. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost allocation riderof alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2024. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2024.
Entergy Louisiana has committed to three two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2024. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2024. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2024.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units were able to fully meet supply needs and obligations in 2023. While deliveries remained constrained through summer 2023, improvements were observed in the second half of the year and are expected to continue in 2024. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2024, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the $67.8 million May 2014 System Agreement bandwidth remedy paymentowner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through 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 refund with interest, with recoveryprevailing 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 payments concludingproviders 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 ensures 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 2023 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction), as well as the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff is subject to change and has recently undergone significant changes. As an example, MISO recently has made changes to its capacity accreditation methodology for thermal resources which emphasize performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now pursuing a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources.
MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO’s functional control. This process generally involves parties that wish to interconnect new generation resources submitting to MISO requests to do so, which are then studied and analyzed by MISO, with the last billing cycleparticipation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO’s current tariff, these requests are studied and considered in December 2015.clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue.
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.
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
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membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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 also foundin 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 retail rates. In the event that Entergy Arkansas is entitlednot able to carrying chargessell 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. 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. The remainder of Entergy Arkansas’s retained share is sold to Entergy Mississippi through a separate life-of-resource purchase power agreement with Entergy Mississippi. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy
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Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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 to System Energy have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement. See Note 8 to the financial statements for discussion of the Reallocation Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, pursuant to which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans
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assumed all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.
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, as well as to Entergy’s non-utility operations business. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations, and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
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
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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 Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Other Business Activities
Entergy’s non-utility operations business includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy’s non-utility operations
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business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy’s non-utility operations business owns interests in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy’s non-utility operations business. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
All generation owned by Entergy’s non-utility operations business falls under the authority of MISO. Customers for the sale of both energy and capacity from its owned generation and contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of the non-utility operations businesses’ owned generation and contracted power purchases are sold under a cost-based contract.
TLG Services, a subsidiary in Entergy’s non-utility operations business, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as 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.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity at or above 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities, certain transmission projects, and certain distribution projects with construction costs greater than $10 million;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2023 of $205.2 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing of the Yucca Mountain repository (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 is in partial breach of 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
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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 2021, 2022, and 2023 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE. Through 2023, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposed a reinstatement of decommissioning cost recovery for ANO 2. In December 2022 the APSC ordered reinstatement of decommissioning collections for ANO 2 in accordance with the request in the November 2022 filing. In November 2023, Entergy Arkansas filed a further revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust continued to be adequately funded, but that ANO 2’s fund continued to require collections higher than those in effect. In December 2023 the APSC approved the proposed higher decommissioning collections for ANO 2.
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
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3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In October 2023 a procedural schedule was adopted that includes a hearing date in August 2024. Management cannot predict the outcome of these proceedings.
In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a base rate case that proposed continuation of the cessation of River Bend decommissioning collections. In May 2023, Entergy Texas filed on behalf of the parties to the base rate case an unopposed settlement, which included an agreement to maintain Entergy Texas’s decommissioning funding for River Bend at a revenue requirement of $0. In August 2023 the PUCT issued an order accepting the unopposed settlement, including the proposed decommissioning funding settlement terms.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. In March 2023 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $165.9 million per reactor (with 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to
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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, “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 with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except River Bend, which is in Column 2.
In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.
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;
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•Interstate Air Transport;
•operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•new and existing source standards for greenhouse gas and other air emissions.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. In April 2023 the EPA issued a regulatory proposal to revise portions of the MATS rule, including a proposed reduction to the emission limit for filterable particulate matter. If finalized, the proposed lower filterable particulate matter emission limitation could require additional capital investment and/or additional other operation and maintenance costs at Entergy’s coal-fired generating units. Entergy is closely monitoring this rulemaking, in part through its various trade associations.
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Good Neighbor Plan/Cross-State Air Pollution Rule
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In June 2023 the EPA published its final Federal Implementation Plan (FIP), known as the Good Neighbor Plan, to address interstate transport for the 2015 ozone NAAQS which would increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Entergy is currently assessing its compliance options for the FIP. Prior to issuance of the FIP, in February 2023 the EPA issued related State Implementation Plan (SIP) disapprovals for many states, including the four states in which the Utility operating companies operate, and these SIP disapprovals are the subject of many legal challenges, including a petition for review filed by Entergy Louisiana challenging the disapproval of Louisiana’s SIP. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the Good Neighbor Plan will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2024. The final FIP also is subject to numerous legal challenges.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop 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.
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 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, NISCO, and Ninemile. Responses to the information collection requests were submitted to the respective state agencies. Louisiana issued its draft SIP which did not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The
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Mississippi Department of Environmental Quality also did not meet the July 31, 2021 SIP submission deadline and continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In 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.
Consistent with the Biden administration’s stated climate goals, in May 2023 the EPA proposed several rules regulating greenhouse gas emissions from new and existing coal and gas-fired power plants. If finalized, the proposed requirements for existing “large and frequently used” gas turbine generating units could require significant investments in CO2 emission reduction technologies at certain of Entergy’s existing gas turbine units with a capacity of greater than 300 MW per combustion turbine and which operate at an annual capacity factor of greater than 50 percent. Comments on the proposed rules were submitted in August 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I, Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the regional cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs) and increased regulation of per- and polyfluorinated substances or other chemicals;
•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 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was subject to multiple legal challenges and was enjoined from implementation or enforcement throughout Entergy’s utility service territory. In May 2023 the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and in September 2023 the EPA and the Corps issued a final rule incorporating the Supreme Court decision. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been 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 April 2015 the EPA published the final coal combustion residuals (CCR) rule regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes regulated under Resource Conservation and Recovery Act Subtitle D. The final regulations created new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria but excluded CCRs that are beneficially reused in certain processes. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed. As of December 31, 2023, Entergy has recorded asset retirement obligations related to CCR management of $28 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each 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 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Additionally, all three sites are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines (ELG). The nature, cost, and timing of those compliance measures depends on the guidance included in the final ELG rule, which is expected by mid-2024.
In May 2023 the EPA released a proposed rule establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (i.e., non-containerized CCR located at a regulated CCR facility). Entergy does not have any legacy impoundments; however, the proposed definition of CCR management units appears to regulate on-site areas where CCR was beneficially used. This is contrary to the current CCR rule which exempts beneficial uses that meet certain criteria. Comments on the proposed rule were submitted in July 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils, and in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP 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 and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the states in which Entergy and the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2023, Entergy subsidiaries employed 12,177 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,302 | |
| Entergy Louisiana | 1,639 | |
| Entergy Mississippi | 747 | |
| Entergy New Orleans | 302 | |
| Entergy Texas | 704 | |
| System Energy | — | |
| Entergy Operations | 3,349 | |
| Entergy Services | 4,117 | |
| Entergy Nuclear Operations | 14 | |
| Other subsidiaries | 3 | |
| Total Entergy | 12,177 | |
There are 3,104 employees represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) (a) | 2023 | | 2022 |
| Female | 23.0 | | 22.2 |
| Male | 77.0 | | 77.8 |
| | | | | | | | | | | |
| Race/Ethnicity (%) (a) | 2023 | | 2022 |
| White | 73.1 | | 74.8 |
| Black/African American | 18.2 | | 17.3 |
| Hispanic/Latino | 3.2 | | 3.0 |
| Asian | 3.2 | | 2.3 |
| Other | 2.3 | | 2.6 |
(a)Based on employees who self-identify.
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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee establishes priorities and each quarter reviews strategies and results on a range of topics covering diversity, culture, and commerce. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee is responsible 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 diversity, culture, and commerce measures, including 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. Entergy employees achieved a total recordable incident rate of 0.49 in 2023 as compared to 0.51 in 2022 and 0.46 in 2021. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022 and 2023, although in early 2024 Entergy experienced a contractor fatality. Also in 2023, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions.
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 2021 of 63 (third quartile), in 2022 of 61 (third quartile), and in 2023 of 62 (third quartile). Although the score is nearly the same in 2023 as in 2022, Entergy has maintained improvement from the 2014 baseline. Improvement in behavioral expectations, which are the leading indicators of outcome improvements, indicates that Entergy is moving in a positive direction.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement for all employees. Entergy is committed to developing and retaining a top-performing workforce that reflects the rich diversity of the communities it serves. In 2021, Entergy established a new Diversity and Workforce Strategies organization to serve as a center of excellence for workforce development, talent attraction/pipeline development, and organizational health and diversity. The organization supports Entergy’s actions to strengthen our partnerships with colleges and vocational-technical schools for a more viable pipeline of future talent while expanding efforts to increase employee engagement and cultivate an inclusive culture with high performance. Entergy continues to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices, and procedures, aligning Employee Resource Group goals to business objectives, growing its DIB Champion network, ensuring that Entergy’s leadership development programs support all employees, 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 highly qualified, 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, proxy statements, and amendments to such filings. 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 https://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, https://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations, and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format); proxy statements; and any amendments to such filings. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. Notwithstanding this reference or any references to the website in this report, the contents of the website are not incorporated into this report.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Item 1A. Risk Factors
See “RISK FACTORS SUMMARY” in Part I, Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s business, financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including, but not limited to, the operation and maintenance of their assets and infrastructure, including with respect to climate or environmental matters, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
events, the quality of their customer service, including timely and accurate billing practices and ability to resolve customer complaints, and the reasonableness of the cost 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 potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, such as through “retail open access” or otherwise, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 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. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or increase 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. Additionally, each Utility operating company’s continued participation in MISO may be affected by the outcomes of proceedings at their respective retail regulators regarding the realized and expected costs and benefits associated with such Utility operating company’s ongoing participation in MISO.
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.
The MISO tariff provisions governing the rights and obligations associated with the resource adequacy construct provided under the MISO tariff are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. As an example, MISO recently has made
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
changes to its capacity accreditation methodology for thermal resources which emphasizes performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now embarking on a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources. Due to their magnitude and, with respect to the changes already made, the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the productionMISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost allocation rider.of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, a large volume of parties and individual generation resources are presently seeking to interconnect to the transmission system MISO administers and over which MISO exercises functional control. Due to the resources and time required to study and evaluate these numerous interconnection requests, including the effects of speculative requests and requests that are withdrawn at late stages of the process, the current MISO interconnection queue to review new requests is subject to significant delays or periods in which MISO does not accept new interconnection requests. These delays present risks to the Utility operating companies and their ability to develop and procure new generation resources to serve their respective loads.
For additional information on MISO regulation and the Utility operating companies’ membership in MISO, see “FederalRegulation of the Utility – Transmission and MISO Markets”section of Part I, Item 1.
Entergy’s and the Utility operating companies’ business, results of operations, and financial condition could be adversely affected by events beyond their control, such as public health crises, natural disasters, geopolitical tensions, or other catastrophic events.
Entergy and the Utility operating companies could be adversely affected by various events beyond their control, including, without limitation, public health crises, natural disasters, geopolitical tensions and other political instability, or other catastrophic events. Any of the foregoing, whether occurring locally, nationally, or globally, and the resulting effects thereof could lead to disruption of the general economy, impacts on the customers of the Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, due to, among other things:
•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;
•adverse impacts on liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense;
•delays in regulatory proceedings;
•regulatory outcomes that require the Utility operating companies to postpone planned investments and otherwise reduce costs due to, for example, the impact of a public health crises or such other catastrophic events on their customers;
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
•workforce availability challenges, including, for example, from infections, health, or safety issues resulting from a public health crisis;
•increased storm recovery costs;
•increased cybersecurity risks as a result of many employees telecommuting;
•volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities on favorable terms), which could in turn, cause a decrease in the value of its defined benefit pension or decommissioning trust funds;
•adverse impacts on Entergy’s credit metrics or ratings;
•governmental mandates in response to any such event; or
•other adverse impacts on their ability to execute on business strategies and initiatives.
To the extent any of these events occur, the business, results of operations, and financial condition of Entergy and the Utility operating companies could be adversely affected.
(Entergy Corporation, Entergy Arkansas, madeEntergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its compliance filing pursuantUtility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the orderimpact of such storm cost recovery on customer bills, especially in January 2015a rising cost environment.
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, droughts, wildfires, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and typically do not have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the APSC issuedUtility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales, such as 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.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Certain of the Utility operating companies and System Energy face risks related to the purchase of uranium fuel (and its approval order,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 the end of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements, supply chain disruptions, limitations or bans on importation of uranium or uranium products from foreign countries, evolving geopolitical conditions such as the wars between Russia and Ukraine and Israel and Hamas, the Nigerien coup, or shifting trade arrangements or sanctions 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 inherent market uncertainties, as well as uncertainties arising from geopolitical conflicts, 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 uninterrupted nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in January 2015.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 or service providers to continue to supply fuel or provide such services at acceptable prices or at all. While such suppliers have performed as expected to date, the future inability of suppliers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The redetermined rate went into effectNRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the first billing cycle of February 2015.
In May 2015, Entergy Arkansas filed its annual redeterminationAtomic Energy Act, related regulations, or the terms of the production cost allocation rider,licenses for nuclear facilities. Interested parties may also intervene in pending proceedings, which includedcould 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 $38 million payment madesubstantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by Entergy Arkansasone 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 FERC’s February 2014 orderincreased oversight activity and potential response costs associated with the
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for certain of the Utility operating companies and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of the Yucca Mountain repository 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 is in partial breach of 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which as of January 1, 2024 is $500 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 $165.9 million per reactor. With 95 reactors currently participating, this translates to a total public liability cap of approximately $15.8 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to 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 $165.9 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is approximately $830 million). The retrospective premium payment is currently limited to approximately $25 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $165.9 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of April 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or if funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.
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 comprehensive bandwidth recalculationdecommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for calendar year 2006, 2007,additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, 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, and Notes 9 and 16 to the financial statements.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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.
Business Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, productionHurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. The occurrence of one or more contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown or unforeseen events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of high interest rates and inflation, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay
Part I Item 1A, 1B, and 1C
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raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm or climate risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.
The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.
As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their businesses. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy’s safety culture or work environment; inability to meet their climate or human capital strategy goals, or failure to demonstrate meaningful progress toward such goals; inability to keep their electricity rates stable; inability to provide quality customer service, including timely and accurate billing; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks, data breaches or physical- or cyber- security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.
Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, investors, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.
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Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with its ability to attract and retain a qualified, inclusive, and diverse workforce, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy’s future cash flows, and this legislation and pending interpretive guidance could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.
Based on initial IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next two to four years.
The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the 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 2023, 2022, 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. For further discussion of the effects of the Inflation Reduction Act of 2022, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities, which judgment may prove to be incorrect or may be disputed by regulators or 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
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regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and 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 the realization of any anticipated benefits from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including achieving Entergy’s climate goals and commitments, which are subject to business, regulatory, economic, shareholder activism 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, each of Entergy Louisiana and Entergy New Orleans have entered into purchase and sale agreements to sell their respective regulated natural gas local distribution company businesses to a third-party. 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 disruptions, import tariffs, and other 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 acquisition or disposition of a business could divert management’s attention from other business concerns;
•Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
•Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.
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The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely and cost-effective manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels and power generation facilities, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
Entergy relies on a large and changing workforce, including employees, contractors, and temporary staffing. Certain factors, such as an aging workforce, mismatching of skill sets for current and future needs, failing to appropriately anticipate future workforce needs, workforce impacts from public health concerns, challenges competing with other employers offering fully remote or more flexible work options, rising salary and other labor costs, unavailability of contract resources, and labor disputes and work disruptions may lead to operating challenges and increased costs. The redetermined ratechallenges include inability to attract or retain talent, lack of resources, loss of knowledge base, and the time required for skill development. 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 specialized 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.
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Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the 2015 production cost allocation rider update was addedcosts of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or the achievement of voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and has proposed regulations for new,
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existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. Various states and regions of the U.S. have taken action to establish greenhouse gas limitations and trading programs. In Louisiana, the former Office of the Governor announced in 2020 the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050, while in 2021, the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units and solar facilities) 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 redeterminedextent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or inability to meet Entergy’s voluntary climate commitments, could negatively impact Entergy’s reputation or inhibit Entergy’s ability to pursue its decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.
Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s Utility operating companies, their suppliers, or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the 2014 productionyear 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy that exceeds Entergy’s or its Utility operating companies’ ability to add lower carbon or carbon-free capacity, load growth, potential tariffs, carbon policy and regulation at the federal or state level, including mandates related to reliability standards, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.
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The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, floods, 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.
Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is pursuing 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 significant weather events, to mitigate the cost of restoration of the electric system after major storms or other significant events, to enable more rapid restoration of electricity after major storm or other significant adverse events, and to deliver electricity to critical customers more immediately after such events. These plans are generally subject to approval by the Utility operating companies’ retail regulators and may not be approved in full or at all. 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.
Additionally, prolonged drought conditions and shifting weather patterns resulting from climate change as well as, among other things, buildup of dry vegetation in areas severely impacted by drought may increase the risk of severe wildfire events within the Utility operating companies’ service areas. Catastrophic wildfires occurring in the Utility operating companies’ service areas could give rise to large damage claims against Entergy or its subsidiaries for fire-related losses alleged to be the result of utility practices and/or the failure of electric and other utility equipment and could also cause Entergy or its subsidiaries to suffer reputational harm or face a more challenging operating, political and regulatory environment.
These and other physical changes could result in, among other things, changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.
A decline in the continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water
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availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, saltwater intrusion, and the potential impacts of climate change on the availability of water resources may cause water use restrictions that affect Entergy and its subsidiaries.
The Utility operating companies, System Energy, and Entergy’s non-utility operations may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-utility operations.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
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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 Entergy’s non-utility business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-utility business.
The hedging and risk management practices of the Utility operating companies and Entergy's non-utility 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 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 benefits 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 has affected and 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 benefits 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 benefits plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which Entergy and the Registrant Subsidiaries operate have
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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 and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems, including disruptions affecting other third parties ultimately connected to Entergy and its subsidiaries or their suppliers through the transmission grid, may adversely affect Entergy’s business and results of operations.
As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors or other third parties interconnected through the grid. Like many businesses and operators of critical infrastructure, Entergy and its subsidiaries and their third-party suppliers have in the past and, will in the future, continue to be subject to cyber attacks, cybersecurity threats and attempts to compromise and penetrate the information technology systems of Entergy and its subsidiaries and disrupt their operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An attack could affect Entergy’s or its subsidiaries’ 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, including threats fueled by artificial intelligence, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. In addition, the prevalent use of smartphones, tablets, and other wireless devices, as well as ongoing remote or hybrid work-from-home arrangement for a significant portion of Entergy’s employees and those of its contractors and vendors may also heighten these risks. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors or other third parties interconnected through the grid, 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. We cannot anticipate, detect, or implement fully preventive measures against all cybersecurity threats.
Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Registrant Subsidiaries’ business, financial condition, results of operations or reputation. Although Entergy and the Registrant
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Subsidiaries purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these incidents. Such incidents may also expose Entergy to an increased risk of litigation (and associated damages and fines). For information on our cybersecurity risk management, strategy, and governance, see “Item 1C. Cybersecurity” in Part I, Item 1C.
Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The global economic cost to insurers resulting from cyber attacks, natural disasters, and other catastrophic events, in addition to an increased focus on climate issues, could have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles, higher premiums, and more restrictive terms and conditions. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.
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 continued inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.
(Entergy Corporation and System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy when required.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas) 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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 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, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy when required. System Energy and its debt securities have been subject to downgrade by rating agencies in the past, most recently in May 2023. Any further downgrade by one or more rating agencies could adversely affect the market prices of System Energy’s debt securities and otherwise adversely affect System Energy’s financial condition.
In addition, an order requiring System Energy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy’s existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy’s financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.
These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Notes 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
Entergy’s non-utility operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy’s non-utility operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-utility operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy’s non-utility operations include legal entities that meet the definition of a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC’s orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.496 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.
Entergy’s non-utility operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market has imposed, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-utility operations’ generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-utility operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy’s non-utility operations’ results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy’s common stock. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy 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, LLC 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, LLC and are therefore subject to prior payment of distributions on its preferred securities.
The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse, and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error, or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.
The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury, and fines and/or penalties and may adversely affect our reputation.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Risk Management and Strategy
Entergy and the Registrant Subsidiaries maintain a security-risk-management system with defined roles, duties, governance, and accountability. Under this physical- and cyber-risk model, Entergy and the Registrant Subsidiaries streamline security into a centralized program. The Chief Security Officer (CSO) is responsible for
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
establishing the security and reliability risk strategy, setting policies, monitoring controls and compliance, providing support activities, and reporting on the security program. The Chief Information Security Officer (CISO) is responsible for establishing the cybersecurity strategy and implementing physical and cyber security systems for the security program. The Chief Ethics & Compliance Officer works with the CSO to address requirements of external security-related regulations, and where applicable, incorporate them into business policies. Management is responsible for identifying and managing risk directly through execution of the security program and compliance with security policies. Entergy and the Registrant Subsidiaries’ risk management model addresses compliance with certain regulatory constructs, such as the NERC Reliability Standards, the NRC Code of Federal Regulations, the Payment Card Industry Data Security Standard, and the Health Insurance Portability and Accountability Act, among other regulations. Entergy and the Registrant Subsidiaries’ risk management model continuously evolves to improve and implement protections, controls, and monitoring to mitigate risks to their part of North America’s electric grid, to protect sensitive information, and to maintain secure business operations. Entergy and the Registrant Subsidiaries manage cybersecurity threats as an enterprise risk with close coordination and information sharing with its federal, state, and local partners. Entergy and the Registrant Subsidiaries also engage with local, state, and federal law enforcement agencies on initiatives to share threat information and participate in a wide range of industry collaborations and classified briefings on cybersecurity developments and evolving risks.
Entergy and the Registrant Subsidiaries maintain access-management controls, including a layered multi-factor authentication process for network and system access, and a defense-in-depth security ecosystem that includes advanced threat detection from independent third parties and federal agencies, security logging and monitoring, and independent third-party penetration and vulnerability assessments. Relevant employees and contractors must complete cybersecurity trainings periodically to heighten security and threat awareness, promote best practices, and meet regulatory requirements. Additional multi-layered prevention and detection processes and technologies to mitigate and minimize the effects of cybersecurity risks include email security, continuous monitoring, vulnerability scanning, anti-virus and anti-malware software, backups and recovery strategy, network segregation, third-party security, and information protection.
Entergy and the Registrant Subsidiaries have incorporated certain cyber-specific response protocols and procedures into their Entergy Incident Management System framework for responding to emergency incidents. This includes the Entergy Incident Response Team Plan, which outlines Entergy’s procedures, steps, and responsibilities for preparing for, detecting, containing, and recovering from an incident. The plan details the roles and responsibilities of Entergy’s officers who would be engaged in such a response to an emergency incident, including key questions to be addressed, critical decision points, and sources of key information to support decision-making. Senior management and the Emergency Incident Response Team periodically review and drill on the plan.
As cybersecurity risks continue to evolve with multiple threat vectors, Entergy and the Registrant Subsidiaries maintain a comprehensive security strategy to keep current with the changing threats. To inform this effort, Entergy and the Registrant Subsidiaries utilize the National Institute of Standards and Technology Cybersecurity Framework, which consists of standards, guidelines, and best practices to manage cybersecurity risk across the enterprise. A risk-based approach is used to direct security initiatives to the most significant risks and provide the most value in terms of risk reduction and protection. Entergy and the Registrant Subsidiaries use a vendor risk management program to assess and monitor security risks that arise from third-party vendors. In addition, Entergy and the Registrant Subsidiaries utilize technology and threat intelligence services to assess and continuously monitor the cybersecurity risk of key vendors, as identified through the vendor risk management program.
While Entergy and the Registrant Subsidiaries have experienced cybersecurity incidents, except as otherwise summarized above or discussed elsewhere in this report, the risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected them including their business strategy, results of operations, or financial condition. See “Item 1A. Risk Factors” in Part I, Item 1A for a detailed description of the risks related to cybersecurity.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Corporate Governance
The Board of Directors is responsible for oversight of the identification, management, and mitigation of enterprise-wide risk, including cybersecurity risk. The Audit Committee has the primary responsibility for overseeing risk management, including oversight of cybersecurity risk management practices and performance. The Audit Committee generally receives reports at each regular quarterly meeting provided by the Chief Information Officer, the CSO, the CISO, and the General Auditor on the cybersecurity management program. The reports focus on the programs and protocols in place to mitigate cybersecurity risks, led by the CSO. Among other things, the reports may include: recent cyber risk and cybersecurity developments; industry engagement activities; legislative and regulatory developments; cyber-risk governance and oversight; selected cyber risk metrics and activities; cyber risk incident response plans and strategies; cybersecurity drills and exercises; assessments by third party experts and Internal Audit; and major projects and initiatives.
While the Board of Directors and Audit Committee oversee cybersecurity risk management, Entergy’s management is responsible for managing cybersecurity risk. Entergy and the Registrant Subsidiaries’ security-risk-management system, as discussed above, is comprised of a three lines of defense model to enhance risk management efforts and define roles in the security program. The first line of defense, comprised of business units performing operational functions, including the CISO, is responsible for identification and management of security and reliability risks directly through design, implementation, and execution of control activities. The second line of defense, comprised of the CSO and Chief Security Office, performs and supports security and reliability risk management and governs and oversees the execution of security and reliability controls by the first line of defense. Ownership of specific security operations may migrate from a business unit in the first line of defense to the second line of defense, as determined to be appropriate by the Chief Security Office. The third line of defense, which includes Internal Audit, independent third parties, and certain regulatory constructs, such as the NERC Reliability Standards and the NRC Cyber Rule, provides assurance of selective actions taken by the first and second lines of defense to senior management and the Board of Directors.
Entergy’s CSO is responsible for overseeing physical, cyber, and reliability risk, including governance, compliance, and threat intelligence. The CSO’s background includes serving as the Global Lead Business Information Security Officer for a multinational pharmaceutical and biotechnology company, Vice President of Cybersecurity Solutions for an international consulting firm, and an operations manager for a multinational technology company. The CSO is also a former intelligence officer in the U.S. Marine Corps, with experience in the Fleet Marine Force, Joint Staff J-2/Defense Intelligence Agency, and Headquarters Marine Corps Command, Control, Communications, and Computers (C4I). The CSO participated in numerous exercises and crisis operations during his time in the military. The CSO is a certified Information Security Manager from the Information Systems Audit and Control Association and a certified Information Privacy Manager from the International Association of Privacy Professionals. The CSO also completed the Harvard Kennedy School Executive Education Program in Cybersecurity and the FBI Domestic Security Executive Academy.
Entergy’s CISO is responsible for enterprise strategic and operational cybersecurity, physical security systems, and regulatory compliance. The CISO oversees investments in tools, resources, and processes that allow for the continuous improvement and maturity of Entergy’s cybersecurity posture. The CISO has expertise spanning more than 25 years in the realm of information technology, information security, and cyber/physical security management. The CISO’s background includes serving as the Vice President and Chief Information Security Officer for an electric utility with responsibility for enterprise cybersecurity covering corporate, electric, nuclear, and gas operations. Additionally, the CISO served as the Chief Security Officer for the Electric Reliability Council of Texas with overall responsibility for its cybersecurity, physical security, and emergency management programs. Her previous experience includes multiple technical, managerial, and strategic roles within industries ranging from energy, telecommunication, software development, and cybersecurity consulting. The CISO is a Certified Information Systems Security Professional, Certified Information Security Manager, and Certified in Risk and Information Systems Control.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
In the event of a suspected or actual cybersecurity incident, the Security Incident Response Team (SIRT), which includes the CISO, has primary responsibility for initial identification and evaluation of potential business impacts and escalation of the incident’s severity classification using pre-established criteria with a specified communication matrix and escalation thresholds. The Security Incident Commander, which role is served by rotating leaders in the CISO organization, provides tactical leadership and oversight management at the cross-functional level for the incident. The SIRT remains engaged throughout the incident response lifecycle, including detection and analysis, containment, eradication and recovery, and post-incident remediation, and coordinates with the impacted business functions, if warranted. Once a cyber incident is confirmed, the SIRT is responsible for maintaining situational awareness and continuous monitoring of the need for escalation or de-escalation of the incident’s severity classification. As certain escalation thresholds are exceeded, additional levels of management notification are required by the SIRT, including notification of and recurring communication with Entergy’s Incident Response Team, which includes the Chief Executive Officer, the Chief Operating Officer, the CSO, other executive management, and members of the affected business functions. Depending upon the facts, analysis, materiality, and anticipated or current impacts, the Chief Executive Officer and the General Counsel will determine the timing and cadence for communication of the cyber incident with the Board of Directors or Audit Committee.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2023 Compared to 2022
Net Income
Net income increased $104 million primarily due to a $159.6 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, higher retail electric price, lower other operation and maintenance expenses, and higher other income. The increase was partially offset by write-offs of $78.4 million ($58.8 million net-of-tax) in third quarter 2023 as a result of Entergy Arkansas’s approved motion to forgo recovery related to the 2013 ANO stator incident, higher interest expense, lower volume/weather, and higher depreciation and amortization expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2023 to 2022:
| | | | | |
| Amount |
| (In Millions) |
| 2022 operating revenues | $2,673.2 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (75.0) | |
| Volume/weather | (31.4) | |
| Retail electric price | 79.6 | |
| 2023 operating revenues | $2,646.4 | |
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 the effect of less favorable weather on residential sales and a decrease in weather-adjusted residential usage, partially offset by an increase in industrial usage. The increase in industrial usage is primarily due to an increase in demand from small industrial customers and 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 January 2023. See Note 2 to the financial statements for further discussion of the 2022 formula rate plan filing.
Entergy Arkansas, Inc.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Arkansas for the years ended December 31, 2023 and 2022 are as follows:
cost allocation rider update | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | | |
| Residential | 7,610 | | | 8,147 | | | (7) | |
| Commercial | 5,584 | | | 5,615 | | | (1) | |
| Industrial | 9,095 | | | 8,493 | | | 7 | |
| Governmental | 192 | | | 218 | | | (12) | |
| Total retail | 22,481 | | | 22,473 | | | — | |
| Sales for resale: | | | | | |
| Associated companies | 2,218 | | | 1,906 | | | 16 | |
| Non-associated companies | 5,777 | | | 6,520 | | | (11) | |
| Total | 30,476 | | | 30,899 | | | (1) | |
See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $17.1 million in compensation and benefits costs primarily due toa decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a revision to estimated incentive compensation expense in first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
•a decrease of $10.5 million in transmission costs allocated by MISO;
•the effects of recording a final judgment in first quarter 2023 to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $10.3 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $9.6 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022.
The decrease was partially offset by:
•an increase of $10.4 million in contract costs related to operational performance, customer service, and organizational health initiatives;
•an increase of $9.2 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023;
•an increase of $5.2 million in nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022 and higher nuclear labor costs; and
•several individually insignificant items.
Asset write-offs includes the effects of Entergy Arkansas forgoing recovery of identified costs resulting from the 2013 ANO stator incident. In third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $68.9 million and the combinedundepreciated balance of $9.5 million in capital costs related to the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
ANO stator incident. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income increased primarily due to:
•higher interest earned on money pool investments;
•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023; and
•a decrease in charitable donations in 2023 as compared to 2022.
Interest expense increased primarily due to the issuance of $425 million of 5.15% Series mortgage bonds in January 2023 and higher interest accrued on spent nuclear fuel disposal costs.
The effective income tax rates were (33.3%) for 2023 and 21.6% for 2022. 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.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $5,278 | | | $12,915 | | | $192,128 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 941,021 | | | 699,732 | | | 549,216 | | |
| Investing activities | (1,032,952) | | | (852,794) | | | (898,193) | | |
| Financing activities | 90,285 | | | 145,425 | | | 169,764 | | |
| Net decrease in cash and cash equivalents | (1,646) | | | (7,637) | | | (179,213) | | |
| | | | | | |
| Cash and cash equivalents at end of period | $3,632 | | | $5,278 | | | $12,915 | | |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2023 Compared to 2022
Operating Activities
Net cash flow provided by operating activities increased $241.3 million in 2023 primarily due to:
•lower 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;
•higher collections from customers;
•the refund of $41.7 millionreceived from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. The refund was subsequently applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;
•a decrease of $38.5 million in pension contributions in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and
•$23.2 million in proceeds received from the DOE in April 2023 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.
The increase was partially offset by:
•the timing of payments to vendors;
•an increase of $25.4 million in storm spending in 2023 as compared to 2022; and
•an increase of $22.1 million in interest paid.
Investing Activities
Net cash flow used in investing activities increased $180.2 million in 2023 primarily due to:
•an increase of $122.9 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023;
•an increase of $86.6 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Arkansas’s transmission system; and
•an increase of $43.2 million as a result of fluctuations in nuclear fuel activity due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
The increase was partially offset by:
•a decrease of $38.3 million in nuclear construction expenditures primarily due to decreased spending on various nuclear projects in 2023;
•$17.9 million in proceeds received from the DOE in April 2023 resulting from litigation regarding spent nuclear fuel storage costs that were previously recorded as plant. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $14.1 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Financing Activities
Net cash flow provided by financing activities decreased $55.1 million in 2023 primarily due to:
•an increase of $331 million in common equity distributions paid in 2023 in order to maintain Entergy Arkansas’s capital structure;
•the repayment, at maturity, of $250 million of 3.05% Series mortgage bonds in June 2023;
•the issuance of $200 million of 4.20% Series mortgage bonds in March 2022;
•the repayment, at maturity, of $40 million of 3.17% Series M notes by the Entergy Arkansas nuclear fuel company variable interest entity in December 2023; and
•money pool activity.
The decrease was partially offset by:
•the issuance of $425 million of 5.15% Series mortgage bonds in January 2023;
•the issuance of $300 million of 5.30% Series mortgage bonds in August 2023;
•net long-term borrowings of $70.2 million in 2023 as compared to net repayments of $4.8 million in 2022 on the nuclear fuel company variable interest entity’s credit facility; and
•an increase of $61.3 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased $35.4 million in 2023 compared to increasing by $40.9 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Arkansas is primarily due to the net issuance of long-term debt in 2023.
| | | | | | | | | | | |
| | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 55.5 | % | | 52.5 | % |
| Effect of subtracting cash | — | % | | — | % |
| Net debt to net capital (non-GAAP) | 55.5 | % | | 52.5 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced 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.
| | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $1,090 | | | $355 | | | $240 | |
| Transmission | 135 | | | 85 | | | 80 | |
| Distribution | 415 | | | 535 | | | 480 | |
| Utility Support | 65 | | | 65 | | | 65 | |
| Total | $1,705 | | | $1,040 | | | $865 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027-2028 | | After 2028 |
| | (In Millions) |
| Long-term debt (a) | $546 | | | $233 | | | $835 | | | $619 | | | $5,514 | |
| Operating leases (b) | $17 | | | $16 | | | $14 | | | $15 | | | $5 | |
| Finance leases (b) | $5 | | | $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 Arkansas currently expects to contribute approximately $55.1 million to its qualified pension plans and approximately $529 thousand to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas has $34.5 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Walnut Bend Solar
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations were conducted, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022. In April 2023, Entergy Arkansas filed an application for an amended certificate of environmental compatibility and public need with the APSC seeking approval by June 2023 for the updates to the cost and schedule that were previously approved by the APSC. In June 2023, Entergy Arkansas, the APSC general staff, and the Arkansas Attorney General filed a unanimous settlement supporting that the approval of the Walnut Bend Solar facility is in the public interest based on the terms
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
in the settlement, including the treatment for the production tax credits associated with the facility. In July 2023, after requesting further testimony and purporting to modify several terms in the settlement and upon rehearing, the APSC approved the settlement largely on the terms submitted, including a 30-year amortization period for the production tax credits. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024, at which time a substantial completion payment of approximately $20 million is expected.
West Memphis Solar
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. In March 2023 the APSC approved Entergy Arkansas’s supplemental application. The project is currently expected to achieve commercial operation by the end of 2024.
Driver Solar
In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas’s petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation as early as mid-2024.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy system money pool;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations,
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | | 2020 |
| (In Thousands) |
| ($145,385) | | ($180,795) | | ($139,904) | | $3,110 |
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 2028. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2024. 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, 2023, 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, 2023, $5.8 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 2025. As of December 31, 2023, $70.2 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 April 2025 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 April 2025. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Retail Rates
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year was 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-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 2015. This combined2021.
2021 Formula Rate Plan Filing
In July 2021, Entergy Arkansas filed with the APSC its 2021 formula rate was effective through December 2015. The collection of the remainder of the redeterminedplan filing to set its formula rate for the 2015 production cost allocation rider update continued through June 2016.2022 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
of return on common equity for the 2022 projected year was 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 was $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 was limited to $72.4 million. In May 2016,October 2021, Entergy Arkansas filed its annual redetermination pursuant towith the production cost allocation rider, which reflected recoveryAPSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the production cost allocation rider true-up adjustment ofsettlement agreement, the 2014total proposed revenue change was $82.2 million, including a $62.8 million increase for the projected 2022 year and 2015 unrecovered retail balancea $19.4 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $72.1 million. In December 2021 the APSC approved the settlement as being in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from apublic interest and approved Entergy Arkansas’s compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update becametariff effective with the first billing cycle of July 2016, and the rates were effective through June 2017.January 2022.
2022 Formula Rate Plan Filing
In May 2017,July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2023 projected year was 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment was $119.9 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 $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas’s overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2023.
2023 Formula Rate Plan Filing
In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment is $130.3 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 $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its annual redetermination pursuantrebuttal in October 2023. In October 2023, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the production cost allocation rider, which reflectedcap constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a credit amount of $0.3 million resulting from a compliance filing pursuant to the FERC’s September 2016 order. Additionally, the redetermined rate reflected10-year period as well as recovery of $34.9 million related to the production cost allocation rider true-up adjustment
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
resolution of the 2016 unrecovered retail balanceand 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the amountpublic interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of $0.3 million. Because of the small effect of the 2017 production cost allocation rider update, Entergy Arkansas proposed to reduce the effective period of the update to one month, July 2017. After the one month collection period, rates were set to zero for all rate classes for the period August 2017 through June 2018.January 2024.
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 redetermination of itsupcoming energy cost rate redetermination filing that was subsequently filedmade in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. Therate $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas 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 iswas available regarding various claims associated with the ANO stator incident. TheIn February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in February 2014.its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement. In October 2023, Entergy Arkansas made a commitment to the APSC to make a filing to forgo its opportunity to seek recovery of the incremental fuel and purchased energy expense, among other identified costs, resulting from the ANO stator incident. As a result, in third quarter 2023, Entergy Arkansas recorded a write-off of its regulatory asset for deferred fuel of $68.9 million, which includes interest, related to the ANO stator incident. Consistent with its October 2023 commitment, Entergy Arkansas filed a motion to forgo recovery in November 2023, and the motion was approved by the APSC in December 2023. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.incident and the approved motion to forgo recovery.
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
Entergy Arkansas, Inc.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 2021, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01052 per kWh to $0.00959 per kWh. The redetermined rate calculation also included an adjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.
In March 2022, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities under its jurisdiction to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC’s draft report issued in its February 2021 winter storms investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas’s emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard. In September 2023 the APSC issued an order in Entergy Arkansas's company-specific proceeding and found that Entergy Arkansas’s practices during the winter storms were prudent.
In March 2023, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.01639 per kWh to $0.01883 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2022 and a $32 million deferral related to the February 2021 winter storms consistent with the APSC general staff’s request in 2022. The under-recovered balance included in the filing was partially offset by the proceeds of the $41.7 million refund that System Energy made to Entergy Arkansas in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See “Complaints Against System Energy - Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue” in Note 2 to the financial statements for discussion of the compliance report filed by System Energy with the FERC in January 2023. The redetermined rate of $0.01883 per kWh became effective with the first billing cycle in April 2023 through the normal operation of the tariff.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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,resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity,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 requestsrequested refunds. In July 2009 the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explainedarguing among other things that the System Agreement clearly 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.
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC’s allegations are without merit. AAfter a hearing, in the matter was held in August 2010.
In December 2010 the ALJ issued an initial decision.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. Quantifying the effect of the FERC’s decision requires re-running intra-system bills for a ten-year period, and theThe FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision.
In August The hearing was held in May 2013 and the presiding judgeALJ issued an initial decision in the calculation proceeding. The initial decision concluded that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concluded that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision recognized that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concluded that any payments by Entergy Arkansas should be reduced by 20%.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, Inc. 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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’sServices’ request to hold the appeal in abeyance pending final resolution of the related proceeding still pending withbefore the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’s appeal and held all ofServices’ appeal.
The hearing required by the appeals in abeyance.
Pursuant to the procedural schedule established in the case, Entergy Services re-ran intra-system bills for the ten-year period 2000-2009 to quantify the effects of the FERC's ruling. In NovemberFERC’s April 2016 the LPSC submitted testimony disputing certain aspects of the calculations. A hearingorder was held in May 2017. In July 2017 the ALJ issued an initial decision concluding that Entergy Arkansas should pay $86 million plus interestaddressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the other Utility operating companies.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. The case is pending before the FERC. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.
The effect of the FERC’s decisions thus far in the case would be that Entergy Arkansas will make payments to some or all of the other Utility operating companies. Because further proceedings will still occur in the case, the amount and recipients of payments by Entergy Arkansas are unknown at this time. 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 includesincluded interest, for its estimated increased costs and payment to the other Utility operating companies. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case, including its review of the July 2017 initial decision. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retailcompanies, and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Entergy Arkansas, therefore, recorded a deferred fuel regulatory asset in the first quarter 2016 of approximately $75 million, which represents its estimate of the retail portion of the costs.million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million. Because management currently expects
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to recovercap the retail portionreduction 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 costs throughLPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a base rate proceeding or newly proposed rider,compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. Refunds and interest in the following amounts were paid by Entergy Arkansas to the other operating companies in December 2018:
| | | | | | | | | | | |
| | Total refunds including interest |
| Payment/(Receipt) |
| | (In Millions) |
| Principal | Interest | Total |
| Entergy Arkansas | $68 | $67 | $135 |
| Entergy Louisiana | ($30) | ($29) | ($59) |
| Entergy Mississippi | ($18) | ($18) | ($36) |
| Entergy New Orleans | ($3) | ($4) | ($7) |
| Entergy Texas | ($17) | ($16) | ($33) |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas previously recognized a regulatory asset is reflected as Other regulatory assetswith a balance of $116 million as of December 31, 2017.2018 for a portion of the payments due as a result of this proceeding.
As described above, the FERC’s opportunity sales orders were appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In July 2021 the D.C. Circuit issued a decision denying all of the petitions for review filed in response to the FERC’s opportunity sales orders.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC’s Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for the Eighth District granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth District affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene. An order from the district court is pending and is anticipated in 2024.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision allows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers advocating the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC’s September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas’s appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC’s decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court’s ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.
Since the enactment of the net metering legislation, the APSC has approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and to utilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also has allowed the aggregation of accounts by net metering customers. These decisions by the APSC have created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy continues to grow as additional net metering applications are approved by the APSC.
In August 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that the statute imposing the expiration of the automatic grandfathering is not ambiguous and that the APSC does not have the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC’s order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Arkansas, sought rehearing, and the Arkansas’s Governor’s executive order limiting new rulemakings calls into question how the APSC’s order to adopt new rules may be effectuated.
In September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in October 2022 with supporting documentation as to the amount and extent of cost shifting and the manner in which they would design tariffs to recover those costs on behalf of non-net metering customers. Responses to the utility and cooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
An Arkansas law was enacted effective March 2023 that revises the billing arrangements for net metering facilities in order to reduce the cost shift to non-net metering customers. The new law also imposes a new limit of 5 MW for future net metering facilities, allows utilities to recover net metering credits in the same manner as fuel, and grandfathers certain net metering facilities that are online or in process to be online by September 2024. Entergy Arkansas joined other utilities in a motion in April 2023 to close the current APSC docket related to potential cost shifting in light of the new law, and the APSC also canceled the remaining procedural schedule in this docket in April 2023. Because of the new law, in May 2023, the APSC also closed the grandfathering rulemaking that it opened in August 2022. Under the new law, the APSC must approve revisions to the utilities’ tariffs to conform to the new law no later than December 2023. The APSC opened a new rulemaking in April 2023 to consider implementation of the new law and tariffs. In October 2023 the APSC issued new net metering rules to conform to the new law, and utilities, including Entergy Arkansas, filed revised net metering tariffs to comply with the new rules on October 16, 2023. Entergy Arkansas’s revised net metering tariff was approved by the APSC in December 2023.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansasgenerating plants and is, therefore, subject to the risks related to owningsuch ownership and operating nuclear plants.operation. 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, including the financial requirements to address emerging issues like stress corrosion crackingrelated to equipment reliability, to position Entergy Arkansas’s nuclear fleet to meet its operational goals; the performance and capacity factors of certain materials within the plant systems and the Fukushima event;these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially availablerecoveries 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.
See Note 8 to the financial statements for discussion of the NRC’s decision in March 2015 to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.
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 principlesGAAP 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 thethese 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.operations, or cash flows.
Entergy Arkansas, Inc. 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.
Unbilled Revenue
See “Unbilled Revenue” 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 unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.
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 impactedaffected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Costs and SensitivitiesSensitivity
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 2024 Qualified Pension Cost | | Impact on 2023 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $929 | | $26,189 |
| Rate of return on plan assets | | (0.25%) | | $2,567 | | $— |
| Rate of increase in compensation | | 0.25% | | $985 | | $4,963 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $3,107 | | $47,040 |
| Rate of return on plan assets | | (0.25%) | | $2,914 | | $- |
| Rate of increase in compensation | | 0.25% | | $1,353 | | $6,446 |
Entergy Arkansas, Inc.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefitbenefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2024 Postretirement Benefits Cost | | Impact on 2023 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | ($56) | | $3,841 |
| Health care cost trend | | 0.25% | | $217 | | $2,600 |
|
| | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $506 | |
| $7,552 |
|
| Health care cost trend | | 0.25% | | $782 | |
| $5,513 |
|
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and FundingEmployer Contributions
Total qualified pension cost for Entergy Arkansas in 20172023 was $37 million.$49.5 million, including $26.1 million in settlement costs. Entergy Arkansas anticipates 20182024 qualified pension cost to be $43 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $13.3$19.6 million. Entergy Arkansas contributed $79.6$54.5 million to its qualified pension planplans in 20172023 and estimates pension contributions will be approximately $64.1$55.1 million in 2018,2024, although the 20182024 required pension contributions will be known with more certainty when the January 1, 20182024 valuations are completed, which is expected by April 1, 2018.2024.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 20172023 was $4$1.9 million. Entergy Arkansas expects 20182024 postretirement health care and life insurance benefit income of approximately $10.2 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $2.5$5.5 million. Entergy Arkansas contributed $695$582 thousand to its other postretirement plans in 20172023 and estimates 20182024 contributions will be approximately $472$529 thousand.
Federal Healthcare LegislationOther Contingencies
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare LegislationContingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
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 the “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 shareholdersmember and Board of Directors of
Entergy Arkansas, Inc.LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc.LLC and Subsidiaries (the “Company”) as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, cash flows and changes in common equity (pages 319336 through 324340 and applicable items in pages 5547 through 230)238), for each of the three years in the period ended December 31, 2017,2023, 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, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters — Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the 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 APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities 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 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 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 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 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 APSC and the FERC and orders issued, 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 to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 201823, 2024
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,646,396 | | | $2,673,194 | | | $2,338,590 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 514,885 | | | 640,344 | | | 347,166 | |
| Purchased power | | 257,890 | | | 201,726 | | | 280,504 | |
| Nuclear refueling outage expenses | | 59,973 | | | 53,438 | | | 51,141 | |
| Other operation and maintenance | | 737,649 | | | 754,293 | | | 687,418 | |
| Asset write-offs | | 78,434 | | | — | | | — | |
| Decommissioning | | 87,321 | | | 82,326 | | | 77,696 | |
| Taxes other than income taxes | | 141,502 | | | 136,565 | | | 127,249 | |
| Depreciation and amortization | | 400,944 | | | 386,272 | | | 361,479 | |
| Other regulatory charges (credits) - net | | (87,409) | | | (89,418) | | | (31,501) | |
| TOTAL | | 2,191,189 | | | 2,165,546 | | | 1,901,152 | |
| | | | | | |
| OPERATING INCOME | | 455,207 | | | 507,648 | | | 437,438 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 20,587 | | | 17,787 | | | 15,273 | |
| Interest and investment income | | 25,024 | | | 19,554 | | | 76,953 | |
| Miscellaneous - net | | (23,216) | | | (27,348) | | | (22,278) | |
| TOTAL | | 22,395 | | | 9,993 | | | 69,948 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 188,232 | | | 150,928 | | | 140,348 | |
| Allowance for borrowed funds used during construction | | (8,270) | | | (7,070) | | | (6,641) | |
| TOTAL | | 179,962 | | | 143,858 | | | 133,707 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 297,640 | | | 373,783 | | | 373,679 | |
| | | | | | |
| Income taxes | | (99,210) | | | 80,896 | | | 75,195 | |
| | | | | | |
| NET INCOME | | 396,850 | | | 292,887 | | | 298,484 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (5,231) | | | (4,358) | | | (18,092) | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $402,081 | | | $297,245 | | | $316,576 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 402,777 |
| | 325,036 |
| | 535,919 |
|
| Purchased power | | 230,652 |
| | 233,350 |
| | 380,081 |
|
| Nuclear refueling outage expenses | | 83,968 |
| | 56,650 |
| | 51,411 |
|
| Other operation and maintenance | | 707,825 |
| | 706,573 |
| | 734,118 |
|
| Decommissioning | | 56,860 |
| | 53,610 |
| | 50,414 |
|
| Taxes other than income taxes | | 103,662 |
| | 93,109 |
| | 99,926 |
|
| Depreciation and amortization | | 277,146 |
| | 264,215 |
| | 246,897 |
|
| Other regulatory charges (credits) - net | | (16,074 | ) | | 7,737 |
| | (24,608 | ) |
| TOTAL | | 1,846,816 |
| | 1,740,280 |
| | 2,074,158 |
|
| | | | | | | |
| OPERATING INCOME | | 293,103 |
| | 346,328 |
| | 179,406 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 18,452 |
| | 17,099 |
| | 14,227 |
|
| Interest and investment income | | 35,882 |
| | 19,087 |
| | 22,382 |
|
| Miscellaneous - net | | (299 | ) | | (1,446 | ) | | (3,385 | ) |
| TOTAL | | 54,035 |
| | 34,740 |
| | 33,224 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 122,075 |
| | 115,311 |
| | 105,622 |
|
| Allowance for borrowed funds used during construction | | (8,585 | ) | | (9,228 | ) | | (7,805 | ) |
| TOTAL | | 113,490 |
| | 106,083 |
| | 97,817 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 233,648 |
| | 274,985 |
| | 114,813 |
|
| | | | | | | |
| Income taxes | | 93,804 |
| | 107,773 |
| | 40,541 |
|
| | | | | | | |
| NET INCOME | | 139,844 |
| | 167,212 |
| | 74,272 |
|
| | | | | | | |
| Preferred dividend requirements | | 1,428 |
| | 5,270 |
| | 6,873 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $138,416 |
| |
| $161,942 |
| |
| $67,399 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
(Page left blank intentionally)
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $396,850 | | | $292,887 | | | $298,484 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 556,780 | | | 532,291 | | | 503,539 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (102,070) | | | 78,958 | | | 100,459 | |
| Asset write-offs | | 78,434 | | | — | | | — | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (84,428) | | | (73,579) | | | 17,682 | |
| Fuel inventory | | (6,351) | | | (252) | | | (7,081) | |
| Accounts payable | | (69,947) | | | 64,944 | | | 27,967 | |
| Taxes accrued | | 4,625 | | | 10,936 | | | 7,753 | |
| Interest accrued | | 16,554 | | | 1,708 | | | (5,637) | |
| Deferred fuel costs | | 228,021 | | | (31,009) | | | (162,458) | |
| Other working capital accounts | | (29,690) | | | (29,789) | | | (53,343) | |
| Provisions for estimated losses | | (21,039) | | | 2,914 | | | 6,915 | |
| Regulatory assets | | (6,197) | | | (120,603) | | | 142,706 | |
| Other regulatory liabilities | | 240,762 | | | (264,054) | | | 21,066 | |
| | | | | | |
| Pension and other postretirement liabilities | | (109,077) | | | (67,783) | | | (175,863) | |
| Other assets and liabilities | | (152,206) | | | 302,163 | | | (172,973) | |
| Net cash flow provided by operating activities | | 941,021 | | | 699,732 | | | 549,216 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (946,244) | | | (785,168) | | | (722,628) | |
| Allowance for equity funds used during construction | | 20,587 | | | 17,787 | | | 15,273 | |
| Nuclear fuel purchases | | (137,616) | | | (98,635) | | | (84,302) | |
| Proceeds from sale of nuclear fuel | | 32,937 | | | 37,198 | | | 16,279 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 117,123 | | | 248,191 | | | 530,628 | |
| Investment in nuclear decommissioning trust funds | | (139,280) | | | (269,497) | | | (524,783) | |
| Payment for purchase of assets | | — | | | (1,044) | | | (131,770) | |
| Change in money pool receivable - net | | — | | | — | | | 3,110 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 17,933 | | | — | | | — | |
| | | | | | |
| | | | | | |
| Decrease (increase) in other investments | | 1,608 | | | (1,626) | | | — | |
| Net cash flow used in investing activities | | (1,032,952) | | | (852,794) | | | (898,193) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,093,253 | | | 232,731 | | | 719,284 | |
| Retirement of long-term debt | | (597,720) | | | (28,521) | | | (728,917) | |
| | | | | | |
| Capital contributions from noncontrolling interest | | — | | | — | | | 51,202 | |
| | | | | | |
| Changes in money pool payable - net | | (35,410) | | | 40,891 | | | 139,904 | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (417,000) | | | (86,000) | | | (50,000) | |
| | | | | | |
| Other | | 47,162 | | | (13,676) | | | 38,291 | |
| Net cash flow provided by financing activities | | 90,285 | | | 145,425 | | | 169,764 | |
| Net decrease in cash and cash equivalents | | (1,646) | | | (7,637) | | | (179,213) | |
| Cash and cash equivalents at beginning of period | | 5,278 | | | 12,915 | | | 192,128 | |
| Cash and cash equivalents at end of period | | $3,632 | | | $5,278 | | | $12,915 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $169,173 | | | $147,060 | | | $143,561 | |
| Income taxes | | $2,705 | | | ($2,753) | | | ($18,933) | |
| Noncash investing activities: | | | | | | |
| Accrued construction expenditures | | $36,264 | | | $93,189 | | | $35,616 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
|
|
|
| |
| For the Years Ended December 31, |
| |
| 2017 |
| 2016 |
| 2015 |
| |
| (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 427,394 |
| | 414,933 |
| | 400,156 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 67,711 |
| | 201,219 |
| | (4,330 | ) |
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (23,397 | ) | | (39,118 | ) | | 20,813 |
|
| Fuel inventory | | 3,402 |
| | 29,929 |
| | (11,791 | ) |
| Accounts payable | | 16,011 |
| | 143,645 |
| | (2,528 | ) |
| Prepaid taxes and taxes accrued | | 40,127 |
| | 37,485 |
| | (54,531 | ) |
| Interest accrued | | 1,635 |
| | (3,303 | ) | | (367 | ) |
| Deferred fuel costs | | 33,190 |
| | (105,741 | ) | | 151,332 |
|
| Other working capital accounts | | 15,087 |
| | (46,490 | ) | | (44,784 | ) |
| Provisions for estimated losses | | 16,047 |
| | 13,130 |
| | (137 | ) |
| Other regulatory assets | | (76,762 | ) | | (95,464 | ) | | 60,279 |
|
| Other regulatory liabilities | | 1,043,507 |
| | 62,994 |
| | (11,123 | ) |
| Deferred tax rate change recognized as regulatory liability/asset | | (1,047,837 | ) | | — |
| | — |
|
| Pension and other postretirement liabilities | | (70,826 | ) | | (36,805 | ) | | (110,936 | ) |
| Other assets and liabilities | | (29,577 | ) | | (67,115 | ) | | 8,565 |
|
| Net cash flow provided by operating activities | | 555,556 |
| | 676,511 |
| | 474,890 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (735,816 | ) | | (666,289 | ) | | (624,546 | ) |
| Allowance for equity funds used during construction | | 19,211 |
| | 17,754 |
| | 15,882 |
|
| Nuclear fuel purchases | | (151,424 | ) | | (102,050 | ) | | (132,252 | ) |
| Proceeds from sale of nuclear fuel | | 51,029 |
| | 39,313 |
| | 52,281 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 339,434 |
| | 197,390 |
| | 212,954 |
|
| Investment in nuclear decommissioning trust funds | | (352,138 | ) | | (213,093 | ) | | (223,357 | ) |
| Payment for purchase of plant | | — |
| | (237,323 | ) | | — |
|
| Changes in money pool receivable - net | | — |
| | — |
| | 2,218 |
|
| Insurance proceeds | | — |
| | 10,404 |
| | 11,654 |
|
| Other | | 392 |
| | 5,899 |
| | (108 | ) |
| Net cash flow used in investing activities | | (829,312 | ) |
| (947,995 | ) |
| (685,274 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 294,656 |
| | 817,563 |
| | — |
|
| Retirement of long-term debt | | (175,560 | ) | | (628,433 | ) | | (13,234 | ) |
| Capital contribution from parent | | — |
| | 200,000 |
| | — |
|
| Redemption of preferred stock | | — |
| | (85,283 | ) | | — |
|
| Change in money pool payable - net | | 114,905 |
| | (1,510 | ) | | 52,742 |
|
| Changes in short-term borrowings - net | | 49,974 |
| | (11,690 | ) | | (36,278 | ) |
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (15,000 | ) | | — |
| | — |
|
| Preferred stock | | (1,428 | ) | | (6,631 | ) | | (6,873 | ) |
| Other | | (8,084 | ) | | (1,158 | ) | | 4,657 |
|
| Net cash flow provided by financing activities | | 259,463 |
| | 282,858 |
| | 1,014 |
|
| Net increase (decrease) in cash and cash equivalents | | (14,293 | ) | | 11,374 |
| | (209,370 | ) |
| Cash and cash equivalents at beginning of period | | 20,509 |
| | 9,135 |
| | 218,505 |
|
| Cash and cash equivalents at end of period | |
| $6,216 |
| |
| $20,509 |
| |
| $9,135 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $115,162 |
| |
| $112,912 |
| |
| $100,435 |
|
| Income taxes | |
| ($8,141 | ) | |
| ($135,709 | ) | |
| $103,296 |
|
| See Notes to Financial Statements. |
| |
|
| |
|
| |
|
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $520 | | | $1,911 | |
| Temporary cash investments | | 3,112 | | | 3,367 | |
| Total cash and cash equivalents | | 3,632 | | | 5,278 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 157,520 | | | 140,513 | |
| Allowance for doubtful accounts | | (7,182) | | | (6,528) | |
| Associated companies | | 124,672 | | | 45,336 | |
| Other | | 89,532 | | | 101,096 | |
| Accrued unbilled revenues | | 117,119 | | | 116,816 | |
| Total accounts receivable | | 481,661 | | | 397,233 | |
| | | | |
| Deferred fuel costs | | — | | | 139,739 | |
| Fuel inventory - at average cost | | 57,495 | | | 51,144 | |
| Materials and supplies - at average cost | | 358,302 | | | 288,260 | |
| Deferred nuclear refueling outage costs | | 35,463 | | | 56,443 | |
| | | | |
| | | | |
| Prepayments and other | | 40,866 | | | 26,576 | |
| | | | |
| TOTAL | | 977,419 | | | 964,673 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,414,009 | | | 1,199,860 | |
| | | | |
| Other | | 801 | | | 2,414 | |
| TOTAL | | 1,414,810 | | | 1,202,274 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 14,821,814 | | | 14,077,844 | |
| | | | |
| Construction work in progress | | 340,601 | | | 417,244 | |
| Nuclear fuel | | 213,722 | | | 176,174 | |
| TOTAL UTILITY PLANT | | 15,376,137 | | | 14,671,262 | |
| Less - accumulated depreciation and amortization | | 6,002,203 | | | 5,729,304 | |
| UTILITY PLANT - NET | | 9,373,934 | | | 8,941,958 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 1,885,361 | | | 1,810,281 | |
| Deferred fuel costs | | — | | | 68,883 | |
| Other | | 21,334 | | | 18,507 | |
| TOTAL | | 1,906,695 | | | 1,897,671 | |
| | | | |
| TOTAL ASSETS | | $13,672,858 | | | $13,006,576 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $6,184 |
| |
| $20,174 |
|
| Temporary cash investments | | 32 |
| | 335 |
|
| Total cash and cash equivalents | | 6,216 |
| | 20,509 |
|
| Securitization recovery trust account | | 3,748 |
| | 4,140 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 110,016 |
| | 102,229 |
|
| Allowance for doubtful accounts | | (1,063 | ) | | (1,211 | ) |
| Associated companies | | 38,765 |
| | 35,286 |
|
| Other | | 65,209 |
| | 58,153 |
|
| Accrued unbilled revenues | | 105,120 |
| | 100,193 |
|
| Total accounts receivable | | 318,047 |
| | 294,650 |
|
| Deferred fuel costs | | 63,302 |
| | 96,690 |
|
| Fuel inventory - at average cost | | 29,358 |
| | 32,760 |
|
| Materials and supplies - at average cost | | 192,853 |
| | 182,600 |
|
| Deferred nuclear refueling outage costs | | 56,485 |
| | 81,313 |
|
| Prepayments and other | | 12,108 |
| | 14,293 |
|
| TOTAL | | 682,117 |
| | 726,955 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Decommissioning trust funds | | 944,890 |
| | 834,735 |
|
| Other | | 3,160 |
| | 7,912 |
|
| TOTAL | | 948,050 |
| | 842,647 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 11,059,538 |
| | 10,488,060 |
|
| Property under capital lease | | — |
| | 716 |
|
| Construction work in progress | | 280,888 |
| | 304,073 |
|
| Nuclear fuel | | 277,345 |
| | 307,352 |
|
| TOTAL UTILITY PLANT | | 11,617,771 |
| | 11,100,201 |
|
| Less - accumulated depreciation and amortization | | 4,762,352 |
| | 4,635,885 |
|
| UTILITY PLANT - NET | | 6,855,419 |
| | 6,464,316 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | — |
| | 62,646 |
|
| Other regulatory assets (includes securitization property of $28,583 as of December 31, 2017 and $41,164 as of December 31, 2016) | | 1,567,437 |
| | 1,428,029 |
|
| Deferred fuel costs | | 67,096 |
| | 66,898 |
|
| Other | | 13,910 |
| | 14,626 |
|
| TOTAL | | 1,648,443 |
| | 1,572,199 |
|
| | | | | |
| TOTAL ASSETS | |
| $10,134,029 |
| |
| $9,606,117 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $375,000 | | | $290,000 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 225,344 | | | 276,362 | |
| Other | | 215,502 | | | 310,339 | |
| Customer deposits | | 113,186 | | | 102,799 | |
| Taxes accrued | | 105,151 | | | 100,526 | |
| | | | |
| Interest accrued | | 35,370 | | | 18,816 | |
| Deferred fuel costs | | 88,282 | | | — | |
| | | | |
| Other | | 55,683 | | | 43,394 | |
| TOTAL | | 1,213,518 | | | 1,142,236 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,437,053 | | | 1,498,234 | |
| Accumulated deferred investment tax credits | | 27,270 | | | 28,472 | |
| Regulatory liability for income taxes - net | | 392,496 | | | 435,157 | |
| Other regulatory liabilities | | 759,181 | | | 475,758 | |
| Decommissioning | | 1,560,057 | | | 1,472,736 | |
| Accumulated provisions | | 58,959 | | | 79,998 | |
| Pension and other postretirement liabilities | | 8,901 | | | 118,020 | |
| Long-term debt | | 4,298,080 | | | 3,876,500 | |
| Other | | 156,673 | | | 97,650 | |
| TOTAL | | 8,698,670 | | | 8,082,525 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,739,071 | | | 3,753,990 | |
| Noncontrolling interest | | 21,599 | | | 27,825 | |
| TOTAL | | 3,760,670 | | | 3,781,815 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $13,672,858 | | | $13,006,576 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $114,700 |
|
| Short-term borrowings | | 49,974 |
| | — |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 365,915 |
| | 239,711 |
|
| Other | | 215,942 |
| | 185,153 |
|
| Customer deposits | | 97,687 |
| | 97,512 |
|
| Taxes accrued | | 47,321 |
| | 7,194 |
|
| Interest accrued | | 18,215 |
| | 16,580 |
|
| Other | | 29,922 |
| | 36,557 |
|
| TOTAL | | 824,976 |
| | 697,407 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,190,669 |
| | 2,186,623 |
|
| Accumulated deferred investment tax credits | | 34,104 |
| | 35,305 |
|
| Regulatory liability for income taxes - net | | 985,823 |
| | — |
|
| Other regulatory liabilities | | 363,591 |
| | 305,907 |
|
| Decommissioning | | 981,213 |
| | 924,353 |
|
| Accumulated provisions | | 34,729 |
| | 18,682 |
|
| Pension and other postretirement liabilities | | 353,274 |
| | 424,234 |
|
| Long-term debt (includes securitization bonds of $34,662 as of December 31, 2017 and $48,139 as of December 31, 2016) | | 2,952,399 |
| | 2,715,085 |
|
| Other | | 5,147 |
| | 13,854 |
|
| TOTAL | | 6,900,949 |
| | 6,624,043 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| Preferred stock without sinking fund | | 31,350 |
| | 31,350 |
|
| | | | | |
| COMMON EQUITY | | |
| | |
|
| Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2017 and 2016 | | 470 |
| | 470 |
|
| Paid-in capital | | 790,264 |
| | 790,243 |
|
| Retained earnings | | 1,586,020 |
| | 1,462,604 |
|
| TOTAL | | 2,376,754 |
| | 2,253,317 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $10,134,029 |
| |
| $9,606,117 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2023, 2022, and 2021 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2020 | $— | | | $3,276,169 | | | $3,276,169 | |
| Net income (loss) | (18,092) | | | 316,576 | | | 298,484 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (50,000) | | | (50,000) | |
| | | | | |
| | | | | |
| Capital contributions from noncontrolling interest | 51,202 | | | — | | | 51,202 | |
| | | | | |
| Balance at December 31, 2021 | $33,110 | | | $3,542,745 | | | $3,575,855 | |
| Net income (loss) | (4,358) | | | 297,245 | | | 292,887 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (86,000) | | | (86,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (927) | | | — | | | (927) | |
| | | | | |
| Balance at December 31, 2022 | $27,825 | | | $3,753,990 | | | $3,781,815 | |
| Net income (loss) | (5,231) | | | 402,081 | | | 396,850 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (417,000) | | | (417,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (995) | | | — | | | (995) | |
| | | | | |
| Balance at December 31, 2023 | $21,599 | | | $3,739,071 | | | $3,760,670 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
|
| | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | |
| | | Common Equity | | |
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | | (In Thousands) | | |
| | | | | | | | | |
| Balance at December 31, 2014 | |
| $470 |
| |
| $588,471 |
| |
| $1,235,296 |
| |
| $1,824,237 |
|
| Net income | | — |
| | — |
| | 74,272 |
| | 74,272 |
|
| Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) |
| Other | | — |
| | 22 |
| | — |
| | 22 |
|
| Balance at December 31, 2015 | |
| $470 |
| |
| $588,493 |
| |
| $1,302,695 |
| |
| $1,891,658 |
|
| Net income | | — |
| | — |
| | 167,212 |
| | 167,212 |
|
| Capital contributions from parent | | — |
| | 200,000 |
| | — |
| | 200,000 |
|
| Capital stock redemption | | — |
| | 1,750 |
| | (2,033 | ) | | (283 | ) |
| Preferred stock dividends | | — |
| | — |
| | (5,270 | ) | | (5,270 | ) |
| Balance at December 31, 2016 | |
| $470 |
| |
| $790,243 |
| |
| $1,462,604 |
| |
| $2,253,317 |
|
| Net income | | — |
| | — |
| | 139,844 |
| | 139,844 |
|
| Common stock dividends | | — |
| | — |
| | (15,000 | ) | | (15,000 | ) |
| Preferred stock dividends | | — |
| | — |
| | (1,428 | ) | | (1,428 | ) |
| Other | | — |
| | 21 |
| | — |
| | 21 |
|
| Balance at December 31, 2017 | |
| $470 |
| |
| $790,264 |
| |
| $1,586,020 |
| |
| $2,376,754 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | | |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | | | | | | | |
| Operating revenues | |
| $2,139,919 |
| |
| $2,086,608 |
| |
| $2,253,564 |
| |
| $2,172,391 |
| |
| $2,190,159 |
|
| Net income | |
| $139,844 |
| |
| $167,212 |
| |
| $74,272 |
| |
| $121,392 |
| |
| $161,948 |
|
| Total assets | |
| $10,134,029 |
| |
| $9,606,117 |
| |
| $8,747,774 |
| |
| $8,777,655 |
| |
| $8,007,707 |
|
| Long-term obligations (a) | |
| $2,983,749 |
| |
| $2,746,435 |
| |
| $2,691,189 |
| |
| $2,757,423 |
| |
| $2,424,969 |
|
| | | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. |
| | | | | | | | | | | |
| | | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | (Dollars In Millions) |
| | | | | | | | | | | |
| Electric Operating Revenues: | | |
| | |
| | |
| | |
| | |
|
| Residential | |
| $768 |
| |
| $789 |
| |
| $824 |
| |
| $755 |
| |
| $772 |
|
| Commercial | | 495 |
| | 495 |
| | 515 |
| | 461 |
| | 469 |
|
| Industrial | | 472 |
| | 446 |
| | 477 |
| | 424 |
| | 433 |
|
| Governmental | | 19 |
| | 18 |
| | 20 |
| | 18 |
| | 19 |
|
| Total retail | | 1,754 |
| | 1,748 |
| | 1,836 |
| | 1,658 |
| | 1,693 |
|
| Sales for resale: | | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 128 |
| | 49 |
| | 128 |
| | 131 |
| | 346 |
|
| Non-associated companies | | 121 |
| | 118 |
| | 195 |
| | 282 |
| | 83 |
|
| Other | | 137 |
| | 172 |
| | 95 |
| | 101 |
| | 68 |
|
| Total | |
| $2,140 |
| |
| $2,087 |
| |
| $2,254 |
| |
| $2,172 |
| |
| $2,190 |
|
| | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | |
| | |
| | |
| | |
|
| Residential | | 7,298 |
| | 7,618 |
| | 8,016 |
| | 8,070 |
| | 7,921 |
|
| Commercial | | 5,825 |
| | 5,988 |
| | 6,020 |
| | 5,934 |
| | 5,929 |
|
| Industrial | | 7,528 |
| | 6,795 |
| | 6,889 |
| | 6,808 |
| | 6,769 |
|
| Governmental | | 237 |
| | 237 |
| | 235 |
| | 238 |
| | 241 |
|
| Total retail | | 20,888 |
| | 20,638 |
| | 21,160 |
| | 21,050 |
| | 20,860 |
|
| Sales for resale: | | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 1,782 |
| | 1,609 |
| | 2,239 |
| | 2,299 |
| | 7,918 |
|
| Non-associated companies | | 6,549 |
| | 7,115 |
| | 7,980 |
| | 8,003 |
| | 1,011 |
|
| Total | | 29,219 |
| | 29,362 |
| | 31,379 |
| | 31,352 |
| | 29,789 |
|
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2023 Compared to 2022
Net Income
2017 Compared to 2016
Net income decreased $305.7increased $417.5 million primarily due to the effectnet effects of Entergy Louisiana’s storm cost securitization in March 2023, including a $133.4 million reduction in income tax expense, partially offset by a $103.4 million ($76.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the enactmentsecuritization regulatory proceeding; a $179.1 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $38 million regulatory charge ($27.8 million net-of-tax) to reflect credits expected to be provided to customers; the reversal of a $105.6 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded in Decemberfourth quarter 2023, as part of the settlement of Entergy Louisiana’s test year 2017 which resulted in a decrease of $182.6 million in net income in 2017, and the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense in 2016. Also contributing to the decrease in net income wereformula rate plan filing; higher retail electric price; higher other income; lower other operation and maintenance expenses.expenses; and higher volume/weather. The decreasenet income increase was partially offset by higherthe net revenue effects of Entergy Louisiana’s storm cost securitization in May 2022, including a $290 million reduction in income tax expense, partially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, and higher other income.depreciation and amortization expenses. See Note 2 to the financial statements for further discussion of the storm cost securitizations and the formula rate plan global settlement. See Note 3 to the financial statements for further discussion of the effectsresolution of the Tax Cuts and Jobs Act and the2016-2018 IRS audit.
2016 Compared to 2015Operating Revenues
Net income increased $175.4 million primarily due to the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense in 2016. Also contributing to the increase were lower other operation and maintenance expenses, higher net revenue, and higher other income. The increase was partially offset by higher depreciation and amortization expenses, higher interest expense, and higher nuclear refueling outage expenses. See Note 3 to the financial statements for discussion of the IRS audit.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenueoperating revenues comparing 20172023 to 2016.
| | | | | |
| Amount |
| | | (In Millions) |
| 2022 operating revenues | Amount$6,338.8 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (In Millions)(1,368.1) | |
| Storm restoration carrying costs | (6.9) | |
2016 net revenueReturn of unprotected excess accumulated deferred income taxes to customers |
24.6 | | $2,438.4
|
Regulatory credit resulting from reduction of the
federal corporate income tax rate
Volume/weather | 55.540.8 | |
| Retail electric price | 42.8118.6 | |
Louisiana Act 55 financing savings obligation2023 operating revenues | 17.2$5,147.8 | |
Volume/weather | (12.4 | ) |
Other | 19.0 |
|
2017 net revenue |
| $2,560.5 |
|
The regulatory credit resultingEntergy Louisiana’s results include revenues from reductionrate 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.
Storm restoration carrying costs represent the equity component of storm restoration carrying costs recognized as part of the federal corporate income tax rate variance is due to the reductionsecuritization of the Vidalia purchased power agreement regulatory liability by $30.5 millionHurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and the reduction of the Louisiana Act 55 financing savings obligation regulatory liabilities by $25 million as a result of the enactment of the Tax Cuts and Jobs Act, in December 2017, which lowered the federal corporate income tax rate from 35% to 21%. The effects of the Tax Cuts and Jobs Act are discussed further in Note 3 to the financial statements.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Hurricane Ida restoration costs in May 2022 and the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Ida restoration costs in March 2023. See Note 2 to the financial statements for discussion of the storm cost securitizations.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018 in response to the enactment of the Tax Cuts and Jobs Act. In 2022, $24.6 million was returned to customers through reductions in operating revenues. There was no return of unprotected excess accumulated deferred income taxes to customers in 2023. There was no effect on net income as the reductions in operating revenues were offset by reductions in income tax expense. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The volume/weather variance is primarily due to the effect of more favorable weather on residential and commercial sales.
The retail electric price variance is primarily due to an increaseincreases in formula rate plan revenues, implemented withincluding increases in the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3distribution and 4 of the Union Power Station in March 2016transmission recovery mechanisms, effective September 2022 and a provision recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding.September 2023. See Note 2 to the financial statements for further discussion of the formula rate plan revenuesproceedings.
Total electric energy sales for Entergy Louisiana for the years ended December 31, 2023 and the Waterford 3 replacement steam generator prudence review proceeding.2022 are as follows:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | | |
| Residential | 14,207 | | | 14,119 | | | 1 | |
| Commercial | 11,074 | | | 10,927 | | | 1 | |
| Industrial | 31,599 | | | 31,666 | | | — | |
| Governmental | 801 | | | 820 | | | (2) | |
| Total retail | 57,681 | | | 57,532 | | | — | |
| Sales for resale: | | | | | |
| Associated companies | 4,406 | | | 5,416 | | | (19) | |
| Non-associated companies | 1,534 | | | 3,423 | | | (55) | |
| Total | 63,621 | | | 66,371 | | | (4) | |
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in 2016 for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike.
See Note 319 to the financial statements for additional discussion of the settlement and benefit sharing.Entergy Louisiana’s operating revenues.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales and decreased usage during the unbilled sales period. The decrease was partially offset by an increase of 1,237 GWh, or 4%, in industrial usage primarily due to an increase in demand from existing customers and expansion projects in the chemicals industry.
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
2015 net revenue |
| $2,408.8 |
|
Retail electric price | 62.5 |
|
Volume/weather | (6.7 | ) |
Louisiana Act 55 financing savings obligation | (17.2 | ) |
Other | (9.0 | ) |
2016 net revenue |
| $2,438.4 |
|
The retail electric price variance is primarily due to an increase in formula rate plan revenues, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station. See Note 2 to the financial statements for further discussion.
The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, partially offset by an increase in industrial usage and an increase in volume during the unbilled period. The increase in industrial usage is primarily due to increased demand from new customers and expansion projects, primarily in the chemicals industry.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
review proceeding. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.
Other Income Statement Variances
2017 Compared to 2016
Other operation and maintenance expenses increaseddecreased primarily due to:
an increase•a decrease of $17.8$27.9 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, to position the nuclear fleet to meet its operational goals, partially offset by a lower scope of work performed during plant outages in 2017;
an increase of $9.5 million in compensation and benefits costs primarily due to lower health and welfare costs, including higher incentive-based compensation accrualsprescription drug rebates in 2017 as compared to the prior year;
an increase of $4.1 millionsecond quarter 2023, a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the amountdiscount rates used to value the benefits liabilities, and a revision to estimated incentive compensation expense in first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
•a decrease of $25.1 million in transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;
an increase•a decrease of $3.6$12.3 million in transmission and distributionnon-nuclear generation expenses due to higher vegetation maintenance costs; and
an increase of $3.2 million in write-offs of customer accounts.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes, state franchise taxes, and payroll taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of Arkansas ad valorem taxes on the Union Power Station beginning in 2017. State franchise taxes increased primarily due to a changelower scope of work, including during plant outages, performed in the2023 as compared to 2022;
Entergy Louisiana, franchise tax law which became effective for 2017.LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•a decrease of $8.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2023 as compared to 2022, lower nuclear labor costs, and lower costs associated with materials and supplies in 2023 as compared to 2022; and
•a decrease of $7.2 million in customer service center support costs primarily due to lower contract costs.
The decrease was partially offset by:
•an increase of $15.9 million in contract costs related to operational performance, customer service, and organizational health initiatives;
•an increase of $6.1 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023; and
•several individually insignificant items.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Blocks 3 and 4service.
Other regulatory charges (credits) - net includes:
•a regulatory charge of $103.4 million, recorded in first quarter 2023, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the Union Power Station purchasedMarch 2023 storm cost securitization;
•a regulatory charge of $224.4 million, recorded in March 2016, and the effects of recordingsecond quarter 2022, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in third quarter 2016 final court decisionsan LPSC ancillary order issued in the River BendHurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Waterford 3 lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $6 million of spent nuclear fuel storage costs previously recorded as depreciation expense.Hurricane Ida securitization regulatory proceeding. See Note 142 to the financial statements for discussion of the Union Power Station purchase.May 2022 storm cost securitization; and
•a regulatory charge of $38 million, recorded in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 83 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.
In addition, Entergy Louisiana records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income increased primarily due to:
•an increase of $113 million in affiliated dividend income from affiliated preferred membership interests related to storm cost securitizations;
•a $31.6 million charge, recorded in second quarter 2022, for the LURC’s 1% beneficial interest in the storm trust I established as part of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida May 2022 storm cost securitization as compared to a $14.6 million charge, recorded in first quarter 2023, for the LURC’s 1% beneficial interest in the storm trust II established as part of the Hurricane Ida March 2023 storm cost securitization. See Note 2 to the financial statements for discussion of the spent nuclear fuel litigation.storm cost securitizations;
•changes in decommissioning trust fund activity, including portfolio rebalancing of certain decommissioning trust funds in 2022; and
Other income increased primarily due to •an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017, which includes the St. Charles Power Station project, and higher realized gains in 2017 on the River Bend decommissioning trust fund investments, including portfolio rebalancing to the 30% interest in River Bend formerly owned by Cajun.2023.
Interest expense decreased primarily due to an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2017, which includes the St. Charles Power Station project.
2016 Compared to 2015
Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outages at Waterford 3.
Other operation and maintenance expenses decreased primarily due to:
the $45 million write-off recorded in 2015 to recognize the portion of the assets associated with the Waterford 3 replacement steam generator project no longer probable of recovery. See Note 2 to the financial statements for further discussion of the prudence review proceeding; and
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
a decrease of $35 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement costs as a result of higher discount rates used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
The decrease was partially offset by an increase of $19.9 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Blocks 3 and 4 of the Union Power Station purchased in March 2016.
Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2016, which included the St. Charles Power Station project, and increased distribution and transmission spending. The increase was also due to higher income in 2016 on the River Bend and Waterford 3 decommissioning trust fund investments.
Interest expense increased primarily due to:
the issuance in March 2016 of $425 million of 3.25% Series collateral trust mortgage bonds;
the issuance in March 2016 of $200 million of 4.95% Series first mortgage bonds; and
the issuance in October 2016 of $400 million of 2.40% Series collateral trust mortgage bonds.
The increase was partially offset byby:
•a decrease of $20.6 million in the refinancing at lower interest ratesamount of certain first mortgage bonds. storm restoration carrying costs recognized in 2023 as compared to 2022, primarily related to Hurricane Ida. See Note 52 to the financial statements for detailsdiscussion of long-term debt.the storm cost securitizations; and
•lower interest income from carrying costs related to the deferred fuel balance.
Income Taxes
The effective income tax rates were (19.3%) for 2017, 2016,2023 and 2015 were 60.5%, 12.6%, and 28.6%, respectively. The difference in the effective income tax rate of 60.5%(23.5%) for 2017 versus the statutory rate of 35% for 2017 was primarily due to the enactment of the Tax Cuts and Jobs Act, signed by President Trump in December 2017, which changed the federal corporate income tax rate from 35% to 21% effective in 2018. See Note 3 to the financial statements for further discussion of the effects of the Tax Cuts and Jobs Act. The difference in the effective income tax rate of 12.6% for 2016 versus the statutory rate of 35% for 2016 was primarily due to the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit in the second quarter 2016 and book and tax differences related to the non-taxable income distributions earned on preferred membership interests, partially offset by state income taxes.2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35%21% to the effective income tax rates.rates and for additional discussion regarding income taxes.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Planned Sale of Gas Distribution Business
See the “Planned Sale of Gas Distribution Businesses” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cutspurchase and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accountingsale agreement for the Act,sale of Entergy Louisiana’s gas distribution business.
Liquidity and Note 2 toCapital Resources
Cash Flow
Cash flows for the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.years ended December 31, 2023, 2022, and 2021 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $56,613 | | | $18,573 | | | $728,020 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 2,032,120 | | | 1,177,508 | | | 1,052,526 | |
| Investing activities | (3,039,456) | | | (4,707,711) | | | (3,700,199) | |
| Financing activities | 953,495 | | | 3,568,243 | | | 1,938,226 | |
| Net increase (decrease) in cash and cash equivalents | (53,841) | | | 38,040 | | | (709,447) | |
| | | | | |
| Cash and cash equivalents at end of period | $2,772 | | | $56,613 | | | $18,573 | |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2023 Compared to 2022
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $213,850 |
| |
| $35,102 |
| |
| $320,516 |
|
| | | | | | |
| Net cash provided by (used in): | | | |
| | |
|
| Operating activities | 1,337,545 |
| | 1,037,912 |
| | 1,155,516 |
|
| Investing activities | (1,787,409 | ) | | (1,474,065 | ) | | (994,208 | ) |
| Financing activities | 271,921 |
| | 614,901 |
| | (446,722 | ) |
| Net increase (decrease) in cash and cash equivalents | (177,943 | ) | | 178,748 |
| | (285,414 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $35,907 |
| |
| $213,850 |
| |
| $35,102 |
|
Operating Activities
Net cash flow provided by operating activities increased $299.6$854.6 million in 20172023 primarily due to:
income tax refunds•a decrease of $234.2$236.7 million in 2017 comparedstorm spending primarily due to income tax paymentsHurricane Ida restoration efforts in 2022;
•an increase of $156.6$42.4 million in 2016. Entergy Louisianainterest received income tax refundsprimarily due to shorter-term financing interest earnings and interest on storm reserve escrow accounts. See Note 2 to the financial statements for a discussion of shorter-term financing interest earnings;
•the refund of $27.8 million received from System Energy in 2017January 2023 related to the sale-leaseback renewal costs and made income tax paymentsdepreciation litigation as calculated in 2016 in accordance with an intercompany income tax allocation agreement. The income tax refunds in 2017 resulted from the utilization of Entergy Louisiana’s net operating losses. The income tax payments in 2016 resulted primarily from adjustments associatedSystem Energy’s January 2023 compliance report filed with the settlementFERC. See Note 2 to the financial statements for further discussion of the 2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit,refund and the effectrelated proceedings;
•a decrease of net operating loss limitations.$9.1 million in pension contributions in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
•lower fuel costs and the timing of recovery of fuel and purchased power costs. See Note 32 to the financial statements for a discussion of fuel and purchased power cost recovery; and
•the timing of payments to vendors.
The increase was partially offset by lower collections from customers and an increase of $14.4 million in interest paid.
Investing Activities
Net cash flow used in investing activities decreased $1,668.3 million in 2023 primarily due to:
•an increase in investment in affiliates in 2022 due to the $3,163.6 million purchase by the storm trust I of preferred membership interests issued by an Entergy affiliate, partially offset by the $1,390.6 million redemption of preferred membership interests. See Note 2 to the financial statements for a discussion of the audits;May 2022 storm cost securitization;
an increase•a decrease of $727 million in distribution construction expenditures primarily due to the timinglower capital expenditures for storm restoration in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
•a decrease of recovery$265.4 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2023 and decreased spending on various transmission projects in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
•$125 million of fuel and purchased power costs; and
an interest paymentredemptions in 2023 of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets.
The increase was partially offset by:
a refund to customers in January 2017 of approximately $71 million as a result of the settlement approvedpreferred membership interests held by the LPSC relatedstorm trust I, as part of periodic redemptions that are expected to occur, subject to certain conditions, for the Waterford 3 replacement steam generator project.preferred membership interests that were issued in connection with the May 2022 storm cost securitization. See Note 2 to the financial statements for discussion of the settlement and refund;
an increase of $62.8 million in spending on nuclear refueling outages; and
proceeds of $37.8 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.May 2022 storm cost securitization and the storm trust I’s investment in preferred membership interests; and
Net cash flow provided by operating activities decreased $117.6•net receipts from storm reserve escrow accounts of $49.6 million in 2016 primarily due to:2023 as compared to net payments to storm reserve escrow accounts of $293.4 million in 2022.
The decrease was partially offset by:
•an increase in investment in affiliates in 2023 due to the $1,457.7 million purchase by the storm trust II of $67.5 million in income tax payments in 2016.preferred membership interests issued by an Entergy Louisiana had income tax payments in 2016 and 2015 in accordance with intercompany income tax allocation agreements. The income tax payments in 2016 resulted primarily from adjustments associated withaffiliate. See Note 2 to the settlementfinancial statements for a discussion of the 2010-2011 IRS audit, payments for state taxes resulting from the effect of the final settlement of the 2006-2007 IRS audit,March 2023 storm cost securitization and the effect of net operating loss limitations. The 2015 income tax payments resulted primarily from adjustments
storm trust II’s investment in preferred membership interests;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits;
•an increase of $80.7 million in interest paid resulting from an increase in interest expense, including a payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets. See Note 10 to the financial statements for a discussion of the purchase of a beneficial interest in the Waterford 3 leased assets;
the timing of collections from customers and payments to vendors; and
a decrease due to the timing of recovery of fuel and purchased power costs in 2016.
The decrease was partially offset by proceeds of $37.8 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed and a decrease of $30.5 million in spending on nuclear refueling outages in 2016. 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 increased $313.3 million in 2017 primarily due to:
an increase of $364.3 million in fossil-fueled generation construction expenditures primarily due to higher spending on the St. Charles Power Station and Lake Charles Power Station projects in 2017;
an increase of $148.9 million in transmission construction expenditures due to a higher scope of work performed in 2017;
an increase of $144.9 million as a result of fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;
proceeds of $57.9 million received in 2016 from the DOE 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;
an increase of $53.6$110.2 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2017;2023;
•an increase of $30.4$47.5 million as a result of fluctuations in distribution construction expendituresnuclear fuel activity due to increased spending on digital technology improvements withinvariations from year to year in the customer contact centers;timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
an increase of $19.9 million due to increased spending on advanced metering infrastructure; and
an increase of $12.3 million due to various information technology projects and upgrades in 2017.
The increase was partially offset by:
the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
•money pool activity; andactivity.
an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2017.
Decreases in Entergy Louisiana’s receivablereceivables from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased by $11.3$14.5 million in 2017 compared to increasing by $16.3 million in 2016.2022. The money pool is an inter-companyintercompany cash management program that makes possible intercompany borrowing arrangementand lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Utility subsidiaries’ need forRegistrant Subsidiaries’ dependence on external short-term borrowings.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Net cash flow used in investing activities increased $479.9 million in 2016 primarily due to:
the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
an increase of $130.7 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016;
cash proceeds of $59.6 million received in 2015 from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “State and Local Rate Regulation and Fuel-Cost Recovery- Retail Rates - Electric - Filings with the City Council” below for further discussion of the transfer;
an increase of $52 million in transmission construction expenditures due to a higher scope of work performed in 2016; and
an increase of $20.5 million due to various information technology projects and upgrades in 2016.
The increase was partially offset by:
fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;
proceeds of $57.9 million received in 2016 from the DOE 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; and
a decrease of $16.9 million in nuclear construction expenditures primarily due to decreased spending on compliance with NRC post-Fukushima requirements.
Financing Activities
Net cash flow provided by financing activities decreased $343$2,614.7 million in 20172023 primarily due to:
•proceeds from securitization of $1.5 billion received by the storm trust II in 2023 as compared to proceeds from securitization of $3.2 billion received by the netstorm trust I in 2022;
•the repayment, at maturity, of $665 million of 0.62% Series mortgage bonds in November 2023;
•the issuance of $325.6$500 million of long-term debt4.75% Series mortgage bonds in 2017 comparedAugust 2022;
•the repayment, at maturity, of $325 million of 4.05% Series mortgage bonds in September 2023;
•the repayment, prior to the net issuancematurity, of $961.2$300 million of 5.59% Series mortgage bonds in December 2023;
•an increase of $36.8 million in 2016. common equity distributions paid in 2023 in order to maintain Entergy Louisiana’s capital structure;
•the repayment, at maturity, of $20 million of 3.22% Series I notes by the Entergy Louisiana Waterford variable interest entity in December 2023; and
•money pool activity.
The decrease was partially offset by:
•a capital contribution of approximately $1.5 billion in 2023 as compared to a capital contribution of approximately $1 billion in 2022, both received indirectly from Entergy Corporation and related to the March 2023 storm cost securitization and the May 2022 storm cost securitization, respectively;
•the repayment, prior to maturity, of $435 million, a portion of the outstanding principal, of 0.62% Series mortgage bonds in May 2022;
•the repayment, at maturity, of $200 million of 3.3% Series mortgage bonds in December 2022;
•the issuance of $70 million of 5.94% Series J notes by the Entergy Louisiana Waterford variable interest entity in September 2023; and
•a decrease of $194.3$25 million in 2023 in net repayments on Entergy Louisiana’s revolving credit facility.
Decreases in Entergy Louisiana’s payable to the money pool are a use of common equity distributions primarily as a result of higher construction expenditurescash flow, and higher nuclear fuel purchasesEntergy Louisiana’s payable to the money pool decreased $69.9 million in 2017; and
net borrowings of $39.7 million on the nuclear fuel company variable interest entities’ credit facilities in 20172023 compared to net repayments of $56.6increasing by $226.1 million in 2016.2022.
Entergy Louisiana’s financing activities provided $614.9 million of cash in 2016 compared to using $446.7 million in 2015 primarily due to the following activity:
the net issuance of $961.2 million of long-term debt in 2016 compared to the net retirement of $103.4 million of long-term debt in 2015;
the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination;
net repayments of borrowings of $56.6 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net borrowings of $14.3 million in 2015; and
an increase of $59.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Blocks 3 and 4 of the Union Power Station.
See Note 5 to the financial statements for details of long-term debt. See Note 2 to the financial statements for discussion of the storm cost securitizations.
2022 Compared to 2021
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Capital Structure
Entergy Louisiana’s capitalizationdebt to capital ratio is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for Entergy Louisiana is primarily due to the $1.5 billion capital contribution received indirectly from Entergy Corporation in March 2023 and the net retirement of long-term debt in 2023.
| | | | | | | | | | | |
| | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 44.9 | % | | 53.0 | % |
| | | |
| | | |
| Effect of subtracting cash | 0.0 | % | | (0.1 | %) |
| Net debt to net capital (non-GAAP) | 44.9 | % | | 52.9 | % |
|
| | | | | |
| | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 53.8 | % | | 53.4 | % |
| Effect of excluding securitization bonds | (0.3 | %) | | (0.5 | %) |
| Debt to capital, excluding securitization bonds (a) | 53.5 | % | | 52.9 | % |
| Effect of subtracting cash | (0.1 | %) | | (0.9 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 53.4 | % | | 52.0 | % |
| |
(a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratios excluding securitization bondsratio in analyzing its financial condition and believes they provideit provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because the securitization bonds are non-recoursecondition. The net debt to Entergy Louisiana, as more fully described in Note 5 to the financial statements.net capital ratio is a non-GAAP measure. Entergy Louisiana also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend,distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce dividends,distributions, or both, to maintain its targeted 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 dividends,reduced distributions, Entergy Louisiana may receive equity contributions to maintain the targetedits 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.
| | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $435 | | | $805 | | | $780 | |
| Transmission | 520 | | | 775 | | | 1,220 | |
| Distribution | 775 | | | 790 | | | 755 | |
| Utility Support | 100 | | | 95 | | | 95 | |
| Total | $1,830 | | | $2,465 | | | $2,850 | |
|
| | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $875 |
| |
| $530 |
| |
| $330 |
|
| Transmission | 465 |
| | 350 |
| | 285 |
|
| Distribution | 325 |
| | 395 |
| | 365 |
|
| Utility Support | 165 |
| | 110 |
| | 135 |
|
| Total |
| $1,830 |
| |
| $1,385 |
| |
| $1,115 |
|
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes investments in generation projects to modernize, decarbonize, and diversify Entergy Louisiana’s portfolio; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations..
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027-2028 | | After 2028 |
| | (In Millions) |
| Long-term debt (a) | $1,719 | | | $659 | | | $983 | | | $1,419 | | | $9,635 | |
| Operating leases (b) | $17 | | | $14 | | | $11 | | | $13 | | | $4 | |
| Finance leases (b) | $6 | | | $5 | | | $4 | | | $6 | | | $3 | |
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $940 |
| |
| $903 |
| |
| $843 |
| |
| $6,785 |
| |
| $9,471 |
|
| Operating leases |
| $22 |
| |
| $41 |
| |
| $24 |
| |
| $19 |
| |
| $106 |
|
| Purchase obligations (b) |
| $633 |
| |
| $1,420 |
| |
| $1,366 |
| |
| $7,125 |
| |
| $10,544 |
|
| |
(a) | Includes estimated interest payments. (a)Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements. |
In addition to the contractualfinancial statements.
(b)Lease obligations given above, are discussed in Note 10 to the financial statements.
Other Obligations
Entergy Louisiana currently expects to contribute approximately $71.9$48.4 million to its qualified pension plans and approximately $19$15 million to its other postretirement health care and life insurance plans in 2018,2024, although the 20182024 required pension contributions will be known with more certainty when the January 1, 20182024, valuations are completed, which is expected by April 1, 2018.2024. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations, Entergy Louisiana has $926.6$128.4 million of unrecognized tax benefits and interest net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments, such asenters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Louisiana has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the St. Charlesfinancial statements for discussion of Entergy Louisiana’s obligations under the Unit Power StationSales Agreement and Lake Charles Power Station, each discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including investment to support advanced metering; resource planning, including potential generation projects; system improvements; investments in River Bend and Waterford 3; and other investments. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements,
Vidalia purchased power agreement.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.
St. Charles Power Station2021 Solar Certification and the Geaux Green Option
In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. The LPSC issued an order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is estimated to occur by mid-2019.
Lake Charles Power Station
In November 2016,2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that the public convenience and necessityare expected to provide $242 million in net benefits to Entergy Louisiana’s customers. These resources, all of which would be served byconstructed in Louisiana, include (i) the constructionVacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025, but are now expected to be no sooner than 2027. The filing proposed to recover the costs of the Lake Charles Power Station,power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.
The proposed Rider GGO is a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacentvoluntary rate schedule that will enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the existing Nelson plant in Calcasieu Parish. The current estimatedresources. Because subscription fees from Rider GGO participants are expected to help offset the cost of the Lake Charles Power Station is $872 million, including estimated costsresources, the design of transmission interconnectionRider GGO also preserves the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and other related costs. capacity benefits of locally-sited solar generation at a discounted price.
In May 2017March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparties to the proceeding agreedVacherie and St. Jacques facilities regarding amendments to an uncontested stipulation finding that constructionthe respective agreements to address the impact of the Lake Charles Power Station is inSt. James Parish ordinance, and the public interest and authorizing an in-service rate recovery plan.facilities are expected to reach commercial operation no sooner than 2027, depending upon agreement by the parties on the terms of the amendments. In July 2017September 2023, Entergy Louisiana reported to the LPSC issued an order unanimously approvingthat it also entered into amended agreements related to the stipulationSunlight Road and approved certificationElizabeth facilities. Both facilities are still expected to achieve commercial operation in 2024.
2022 Solar Portfolio and Expansion of the unit. Construction is in progress and commercial operation is expected to occur by mid-2020. Geaux Green Option
Washington Parish Energy Center
In April 2017, Entergy Louisiana signed a purchase and sale agreement with a subsidiary of Calpine Corporation for the acquisition of a peaking plant. Calpine will construct the plant, which will consist of two natural gas-fired combustion turbine units with a total nominal capacity of approximately 361 MW. The plant, named the Washington Parish Energy Center, will be located in Bogalusa, Louisiana and, subject to permits and approvals, is expected to be completed in 2021. Subject to regulatory approvals, Entergy Louisiana will purchase the plant once it is complete for an estimated total investment of approximately $261 million, including transmission and other related costs. In May 2017,February 2023, Entergy Louisiana filed an application with the LPSC seeking certification of the plant. A procedural schedule has been established,Iberville/Coastal Prairie facility, which will provide 175 MW of capacity through a PPA with the deadlines recently extendeda third party, and the hearing continued from March 2018 until June 2018 in order to allowSterlington facility, a 49 MW self-build project located near the parties an opportunity to reach settlement.
Advanced Metering Infrastructure (AMI)
In November 2016,deactivated Sterlington power plant (the 2022 Solar Portfolio). Entergy Louisiana filed an applicationis seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing included an estimate of implementation costs for AMI of $330 million. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate basethese resources within the remaining book value, approximately $92 million at December 31, 2015, ofportfolio supporting the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. The communications network deployment
Rider GGO
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
rate schedule to help fulfill customer interest in access to renewable energy. Entergy Louisiana has requested the costs of these facilities, as offset by Rider GGO revenues, be deemed eligible for recovery in accordance with the terms of the formula rate plan and fuel adjustment clause rate mechanisms that exist at the time the facilities are placed into service. In January 2024, the parties filed an uncontested stipulated settlement agreement on the key issues in the case, which stated that the 2022 Solar Portfolio should be constructed, found that Entergy Louisiana’s proposed cost recovery mechanisms were appropriate, and confirmed the resources’ eligibility for inclusion in Rider GGO. The settlement was approved by the LPSC in January 2024. The Sterlington facility is expected to begin by late-2018, after the necessary information technology infrastructure isachieve commercial operation in place.January 2026.
Alternative RFP and Certification
In March 2023, Entergy Louisiana made the first phase of a bifurcated filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the current RFP and certification process allows. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing, which contains the details of the proposal for the alternative competitive procurement process and the information necessary to support certification, was filed in May 2023. In addition to the acquisition of up to 3 GW of solar resources, the filing also seeks approval of a new renewable energy credits-based tariff, Rider Geaux ZERO. Several parties have intervened, and a procedural schedule was established in May 2023 with a hearing scheduled for March 2024. In October 2023 the LPSC staff and intervenors filed testimony, with the LPSC staff supporting the amount of solar resources to be acquired and the alternative RFP process. The LPSC staff also supported, subject to certain recommendations, the proposed framework for evaluation and certification of the solar resources by the LPSC and the proposed tariff.
System Resilience and Storm Hardening
In December 2022, Entergy Louisiana filed an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the costprogram’s costs. Phase I reflects the first five years of AMI through thea ten-year resilience plan and includes investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2023 a procedural schedule was established with a hearing scheduled for January 2024. The LPSC staff and certain intervenors filed direct testimony in August, September, and October 2023. The LPSC staff filed cross-answering testimony in October 2023. The testimony largely supports implementation of a customer charge, netsome level of certain benefits, phasedaccelerated investment in over the period 2019 through 2022. The parties reached an uncontested stipulation permitting implementation of Entergy Louisiana’s proposed AMI system, with modificationsresilience, but raises various issues related to the proposed customer charge.magnitude of the investment, the cost recovery mechanism applicable to the investment, and the ratemaking for the investment. In July 2017January 2024 the hearing in this matter was rescheduled to April 2024.
The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC approvedstaff issued a draft rule in the stipulation.rulemaking proceeding related to a requirement to file a grid resilience plan. The procedural schedule entered in the rulemaking proceeding contemplated adoption of a final rule in October 2023, but this did not occur, and a new date has not been set. The LPSC also has pending rulemakings addressing issues related to pole viability and grid maintenance practices. In December 2023, in those rulemakings, the LPSC staff issued a report and recommendation proposing to impose significant new reporting and compliance obligations related to jurisdictional utilities’ distribution and transmission operations, including new obligations related to grid hardening plans, pole inspections, pole replacement, vegetation management, storm restoration plans, new reliability metrics, software for handling customer complaints and complaint resolution, required use of drone technology, and new penalties and incentives for reliability performance and for compliance with the new obligations. In February 2024, Entergy Louisiana expects to recoverand other parties filed comments on the undepreciated balanceLPSC staff’s report.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy system money pool;
•storm reserve escrow accounts;
•debt or preferred membership interest issuances;issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Louisiana may refinance, redeem, or otherwiseexpects to continue, when economically feasible, to retire higher-cost debt prior to maturity, to the extentand replace it with lower-cost debt if market conditions and interest rates are favorable.permit.
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Preferred membership interest and debtDebt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.needs for the next twelve months and beyond.
Entergy Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | | 2020 |
| (In Thousands) |
| ($156,166) | | ($226,114) | | $14,539 | | $13,426 |
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| $11,173 | | $22,503 | | $6,154 | | $2,815 |
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 August 2022.June 2028. The credit facility allows Entergy Louisiana to issueincludes fronting commitments for the issuance of letters of credit against $15 million of the borrowing capacity of the facility. As of December 31, 2017,2023, there were no cash borrowings and a $9.1 million letterno 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, 2017, a $29.72023, $17.1 million letterin letters of credit waswere outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, oneeach in the amount of $105 million and one in the amount of $85 million, both scheduled to expire in May 2019.June 2025. As of December 31, 2017, $65.72023, $46.6 million ofin loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2017, $43.5 million in letters of credit to support a like amount of commercial paper issued and $36.42023, $29.5 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, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana obtained authorizations from the FERC through October 2019April 2025 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
long-term •borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane IsaacIda
In June 2014 the LPSC voted to approve a series of orders which (i) quantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred; (ii) determined $290 million as the level of storm reserves to be re-established; (iii) authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation and the Louisiana State Bond Commission. SeeAs discussed in Note 2 to the financial statements, forin August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s distribution and, to a discussion of the August 2014 issuance of bonds under Act 55 of the Louisiana Legislature.lesser extent, transmission systems resulting in widespread power outages.
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC staff and intervenors filed testimony. The LPSC staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Louisiana to recover $200 million as of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011,2022, Entergy Louisiana filed an application with the LPSC relating to authorizeHurricane Ida restoration costs. Total restoration costs for the securitizationrepair and/or replacement of the investmentEntergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the projectrestoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed in Note 2 to the financial statements, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023, the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the Louisiana Local Government Facilities and Community Development Authority (LCDA) to issue athe bonds authorized in the LPSC’s financing order by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlement and also
order.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).
Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust II to purchase 14,576,757.48 Class B preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company, LLC, a financing ordermajority owned indirect subsidiary of Entergy. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2023 on the preferred membership interests issued to the storm trust II. These annual dividends received by the storm trust II will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust II. Specifically, 1% of the annual dividends received by the storm trust II will be distributed to the LURC for the securitization. Seebenefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7.5% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.
Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of April 2023 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust II is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.
From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company loaned approximately $1.5 billion to Entergy, which was indirectly contributed to Entergy Louisiana as a capital contribution.
As discussed in Note 53 to the financial statements, the securitization resulted in recognition of a net reduction of income tax expense of approximately $133 million, after taking into account a provision for uncertain tax positions, by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was offset by other tax charges resulting in a discussionnet reduction of the September 2011 issuanceincome tax expense of $129 million, after taking into account a provision for uncertain tax positions. In recognition of its obligations described in an LPSC ancillary order issued as part of the securitization bonds.regulatory proceeding, Entergy Louisiana recorded in first quarter 2023 a $103 million ($76 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.
As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.
Nelson Industrial Steam Company
Entergy Louisiana is a partner in the Nelson Industrial Steam Company (NISCO) partnership which owns two petroleum coke generating units. In April 2023 these generating units suspended operations in the MISO market, and Entergy Louisiana currently is working to wind up the NISCO partnership, which will ultimately result in ownership of the generating units transferring to Entergy Louisiana. In November 2023 the FERC issued an order providing Section 203 of the Federal Power Act approval for any subsequent transfer of the facilities to Entergy Louisiana. Entergy Louisiana is evaluating the effect of the transaction on its results of operations, cash flows, and financial condition, but at this time does not expect the effect to be material.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
FilingsRetail Rates - Gas
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of the upper end of the earnings band as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015. In April 2022 Entergy Louisiana submitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC staff submitted an uncontested settlement that extends the rider for an additional ten years beginning after the end of the current term of the rider in 2025. The extension is subject to the same customer safeguards and conditions as the original term of the rider. The extension
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allows for recovery of approximately $95 million over ten years. In February 2023, the uncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.
Other
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, and limited discovery has occurred.
In December 2019 an LPSC commissioner issued an unopposed directive to staff to research customer-centered options for all customer classes, as well as other regulatory environments, and recommend a plan for how to ensure customers are the focus. There was no opposition to the directive from other commissioners but several remarked that the intent of the directive was not initiated to pursue retail open access. In furtherance of the directive, the LPSC issued a notice of the opening of a docket to conduct a rulemaking to research and evaluate customer-centered options for all electric customer classes as well as other regulatory environments in January 2020. To date, the LPSC staff has requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the LPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Mississippi
Formula Rate Plan Filing
Since the conclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a formula rate plan. Between base rate cases, Entergy Mississippi is able to adjust base rates annually, subject to certain caps, through formula rate plans that utilize forward-looking features. In addition, Entergy Mississippi is subject to an annual “look-back” evaluation. Entergy Mississippi is allowed a maximum rate increase of 4% of each test year’s retail revenue. Any increase above 4% requires a base rate case. If Entergy Mississippi’s formula rate plan were terminated without replacement, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the MPSC opened inquiries to review whether the then-current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the
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return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 1 of the filing year on a temporary basis subject to refund or credit to customers, subject to final MPSC order. The MPSC also authorized Entergy Mississippi to remove vegetation management costs from the formula rate plan and recover these costs through the establishment of a vegetation management rider.
In 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.
In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the annual power management and grid modernization riders effective January 2023.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of over- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
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Other
In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the 2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule.
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. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.
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.
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 filings to recover storm-related costs.
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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 and Purchased Power Cost 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. Historically, semi-annual revisions of the fixed fuel factor have been made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 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. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the PUCT to undertake a rulemaking to effectuate the new legislation by the end of 2024.
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 to be recovered through a purchased power capacity rider. No Texas utility, including Entergy Texas, has exercised the option to recover capacity costs under the rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs. In 2023, the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through a purchased power capacity rider.
Transmission, Distribution, and Generation 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 permitted 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. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their
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distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Other
In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.
As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.
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
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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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric
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service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2024-2058.
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, 2023 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,036 | | | 1,548 | | | 521 | | | 1,825 | | | 969 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,798 | | | 5,594 | | | 2,728 | | | 2,137 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,904 | | | 1,744 | | | 641 | | | — | | | 417 | | | — | | | 102 | |
| Entergy New Orleans | | 662 | | | 635 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,234 | | | 990 | | | 1,994 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,245 | | | — | | | — | | | 1,245 | | | — | | | — | | | — | |
| Total | | 23,879 | | | 10,511 | | | 5,884 | | | 5,207 | | | 1,975 | | | 73 | | | 229 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,775 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 7,963 MW of new long-term resources and the deactivation of about 4,241 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
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products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•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. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 2021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC’s approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the St. Jacques facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar
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facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
•Entergy Louisiana expects to start construction on the 49 MW Sterlington Solar project in the fourth quarter 2024, located in Sterlington, Louisiana. The facility is expected to achieve commercial operation in January 2026.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
•River Bend’s 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
•Entergy Arkansas’s wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
•In September 2012, Entergy Gulf States Louisiana and Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from a 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 and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a 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 and TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, executed a 10-year agreement to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;
•Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
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•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
•In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
•In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC
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requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
•In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, 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 as early as June 2026.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. Entergy Louisiana selected a combination of PPA and build own transfer resources in March 2023 some of which have been executed and are noted above, and negotiation of definitive agreements for the remaining resources are in progress.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2023, and negotiation of definitive agreements are in progress for all resources.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including among others:
•In March 2016, Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) 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). The facility is located near El Dorado, Arkansas and has been in operation since July 2003;
•In October 2019, Entergy Mississippi’s acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The facility is located in Choctaw County and has been in operation since July 2003;
•In November 2020, Entergy Louisiana’s acquisition of 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. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
•In June 2021, Entergy Texas’s acquisition of 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. The facility has been in operation since January 2010; and
•In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC voted to approve this project and in September 2023, Entergy Louisiana reported
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to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.
In December 2020, Entergy Texas filed an application with the PUCT to amend its certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its 2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. A procedural schedule has not yet been set.
In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas’s proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A
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paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas’s rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC’s order.
In July 2021, Entergy Louisiana filed with the LPSC an application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to the terms of the settlement agreement, Entergy Louisiana may seek to expand the distributed generation program following the earlier of two years after issuance of an order approving the settlement or the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2022.
Interconnections
The Utility operating companies’ generating units are interconnected to the transmission system which operates at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined-cycle combustion turbine generators and reciprocating internal combustion engine generators that are fueled by natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage devices that participate in the MISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include generating and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2023, 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, 2023, 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
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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 average fuel cost per kWh for the Utility operating companies and System Energy for the years 2021-2023 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2023 | | (Cents Per kWh) |
| Entergy Arkansas | | 1.98 | | | 0.50 | | | 3.09 | | | 1.98 | | | 11.57 | | | 0.77 | |
| Entergy Louisiana | | 2.34 | | | 0.60 | | | 3.22 | | | 10.38 | | | 3.76 | | | 2.50 | |
| Entergy Mississippi | | 2.21 | | | — | | | 2.82 | | | 0.03 | | | 5.86 | | | 1.84 | |
| Entergy New Orleans (c) | | 2.05 | | | — | | | — | | | 3.24 | | | — | | | 2.33 | |
| Entergy Texas | | 2.29 | | | — | | | 3.17 | | | 2.25 | | | 5.64 | | | 3.18 | |
| System Energy | | — | | | 0.68 | | | — | | | — | | | — | | | — | |
| Utility | | 2.25 | | | 0.58 | | | 3.06 | | | 6.14 | | | 4.03 | | | 2.61 | |
| | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $0.1 million in 2023, $2.9 million in 2022, and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2023 and projected 2024 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | 1 | % | | 57 | % | | 9 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 47 | % | | 7 | % | | 20 | % | | 2 | % | | 2 | % | | 10 | % | | 12 | % |
| Entergy Mississippi | 63 | % | | 1 | % | | 23 | % | | 7 | % | | 1 | % | | — | % | | 5 | % |
| Entergy New Orleans | 55 | % | | 1 | % | | 36 | % | | 1 | % | | 2 | % | | 1 | % | | 4 | % |
| Entergy Texas | 32 | % | | 25 | % | | 6 | % | | 3 | % | | — | % | | 4 | % | | 30 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 43 | % | | 7 | % | | 27 | % | | 4 | % | | 2 | % | | 5 | % | | 12 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 59 | % | | 12 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 48 | % | | 6 | % | | 30 | % | | 2 | % | | 3 | % | | 11 | % | | — | % |
| Entergy Mississippi | 64 | % | | — | % | | 24 | % | | 10 | % | | 2 | % | | — | % | | — | % |
| Entergy New Orleans | 51 | % | | 1 | % | | 43 | % | | 1 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 43 | % | | 31 | % | | 17 | % | | 6 | % | | 3 | % | | — | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 45 | % | | 6 | % | | 35 | % | | 6 | % | | 3 | % | | 5 | % | | — | % |
(a)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2023 is not projected for 2024.
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 2024, 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 70% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply at least 85% of the total coal supply needs in 2024. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2024. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2024.
Entergy Louisiana has committed to three two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2024. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2024. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2024.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units were able to fully meet supply needs and obligations in 2023. While deliveries remained constrained through summer 2023, improvements were observed in the second half of the year and are expected to continue in 2024. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2024, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through 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 ensures 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 2023 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction), as well as the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff is subject to change and has recently undergone significant changes. As an example, MISO recently has made changes to its capacity accreditation methodology for thermal resources which emphasize performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now pursuing a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources.
MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO’s functional control. This process generally involves parties that wish to interconnect new generation resources submitting to MISO requests to do so, which are then studied and analyzed by MISO, with the participation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO’s current tariff, these requests are studied and considered in clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue.
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.
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
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membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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 retail 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. 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. The remainder of Entergy Arkansas’s retained share is sold to Entergy Mississippi through a separate life-of-resource purchase power agreement with Entergy Mississippi. 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 approvaloriginal financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy
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Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
Each of the business combinationassignment 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 to System Energy have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement. See Note 8 to the financial statements for discussion of the Reallocation Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, pursuant to which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans
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assumed all of Entergy Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement.
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, as well as to Entergy’s non-utility operations business. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations, and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson Unit 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.
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
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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 Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Other Business Activities
Entergy’s non-utility operations business includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy’s non-utility operations
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business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy’s non-utility operations business owns interests in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy’s non-utility operations business. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
All generation owned by Entergy’s non-utility operations business falls under the authority of MISO. Customers for the sale of both energy and capacity from its owned generation and contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of the non-utility operations businesses’ owned generation and contracted power purchases are sold under a cost-based contract.
TLG Services, a subsidiary in Entergy’s non-utility operations business, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as 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.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, environmental adjustment charge, and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•certification of certain transmission projects;
•certification of capacity acquisitions, both for owned capacity and for purchase power contracts that exceed either 5 MW or one year in term;
•procurement process to acquire capacity at or above 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities, certain transmission projects, and certain distribution projects with construction costs greater than $10 million;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2023 of $205.2 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing of the Yucca Mountain repository (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 is in partial breach of 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
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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 2021, 2022, and 2023 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE. Through 2023, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposed a reinstatement of decommissioning cost recovery for ANO 2. In December 2022 the APSC ordered reinstatement of decommissioning collections for ANO 2 in accordance with the request in the November 2022 filing. In November 2023, Entergy Arkansas filed a further revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust continued to be adequately funded, but that ANO 2’s fund continued to require collections higher than those in effect. In December 2023 the APSC approved the proposed higher decommissioning collections for ANO 2.
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
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3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In October 2023 a procedural schedule was adopted that includes a hearing date in August 2024. Management cannot predict the outcome of these proceedings.
In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a base rate case that proposed continuation of the cessation of River Bend decommissioning collections. In May 2023, Entergy Texas filed on behalf of the parties to the base rate case an unopposed settlement, which included an agreement to maintain Entergy Texas’s decommissioning funding for River Bend at a revenue requirement of $0. In August 2023 the PUCT issued an order accepting the unopposed settlement, including the proposed decommissioning funding settlement terms.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. In March 2023 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $165.9 million per reactor (with 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to
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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, “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 with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except River Bend, which is in Column 2.
In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.
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;
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•Interstate Air Transport;
•operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•new and existing source standards for greenhouse gas and other air emissions.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. In April 2023 the EPA issued a regulatory proposal to revise portions of the MATS rule, including a proposed reduction to the emission limit for filterable particulate matter. If finalized, the proposed lower filterable particulate matter emission limitation could require additional capital investment and/or additional other operation and maintenance costs at Entergy’s coal-fired generating units. Entergy is closely monitoring this rulemaking, in part through its various trade associations.
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Good Neighbor Plan/Cross-State Air Pollution Rule
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In June 2023 the EPA published its final Federal Implementation Plan (FIP), known as the Good Neighbor Plan, to address interstate transport for the 2015 ozone NAAQS which would increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Entergy is currently assessing its compliance options for the FIP. Prior to issuance of the FIP, in February 2023 the EPA issued related State Implementation Plan (SIP) disapprovals for many states, including the four states in which the Utility operating companies operate, and these SIP disapprovals are the subject of many legal challenges, including a petition for review filed by Entergy Louisiana challenging the disapproval of Louisiana’s SIP. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the Good Neighbor Plan will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2024. The final FIP also is subject to numerous legal challenges.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop 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.
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 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, NISCO, and Ninemile. Responses to the information collection requests were submitted to the respective state agencies. Louisiana issued its draft SIP which did not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The
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Mississippi Department of Environmental Quality also did not meet the July 31, 2021 SIP submission deadline and continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In 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.
Consistent with the Biden administration’s stated climate goals, in May 2023 the EPA proposed several rules regulating greenhouse gas emissions from new and existing coal and gas-fired power plants. If finalized, the proposed requirements for existing “large and frequently used” gas turbine generating units could require significant investments in CO2 emission reduction technologies at certain of Entergy’s existing gas turbine units with a capacity of greater than 300 MW per combustion turbine and which operate at an annual capacity factor of greater than 50 percent. Comments on the proposed rules were submitted in August 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I, Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
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Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the regional cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs) and increased regulation of per- and polyfluorinated substances or other chemicals;
•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 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015
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definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was subject to multiple legal challenges and was enjoined from implementation or enforcement throughout Entergy’s utility service territory. In May 2023 the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and in September 2023 the EPA and the Corps issued a final rule incorporating the Supreme Court decision. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been 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 April 2015 the EPA published the final coal combustion residuals (CCR) rule regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes regulated under Resource Conservation and Recovery Act Subtitle D. The final regulations created new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria but excluded CCRs that are beneficially reused in certain processes. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed. As of December 31, 2023, Entergy has recorded asset retirement obligations related to CCR management of $28 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each 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 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.
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Additionally, all three sites are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines (ELG). The nature, cost, and timing of those compliance measures depends on the guidance included in the final ELG rule, which is expected by mid-2024.
In May 2023 the EPA released a proposed rule establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (i.e., non-containerized CCR located at a regulated CCR facility). Entergy does not have any legacy impoundments; however, the proposed definition of CCR management units appears to regulate on-site areas where CCR was beneficially used. This is contrary to the current CCR rule which exempts beneficial uses that meet certain criteria. Comments on the proposed rule were submitted in July 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils, and in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP 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 and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the states in which Entergy and the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2023, Entergy subsidiaries employed 12,177 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,302 | |
| Entergy Louisiana | 1,639 | |
| Entergy Mississippi | 747 | |
| Entergy New Orleans | 302 | |
| Entergy Texas | 704 | |
| System Energy | — | |
| Entergy Operations | 3,349 | |
| Entergy Services | 4,117 | |
| Entergy Nuclear Operations | 14 | |
| Other subsidiaries | 3 | |
| Total Entergy | 12,177 | |
There are 3,104 employees represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) (a) | 2023 | | 2022 |
| Female | 23.0 | | 22.2 |
| Male | 77.0 | | 77.8 |
| | | | | | | | | | | |
| Race/Ethnicity (%) (a) | 2023 | | 2022 |
| White | 73.1 | | 74.8 |
| Black/African American | 18.2 | | 17.3 |
| Hispanic/Latino | 3.2 | | 3.0 |
| Asian | 3.2 | | 2.3 |
| Other | 2.3 | | 2.6 |
(a)Based on employees who self-identify.
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.
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Entergy Corporation, Utility operating companies, and System Energy
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee establishes priorities and each quarter reviews strategies and results on a range of topics covering diversity, culture, and commerce. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee is responsible 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 diversity, culture, and commerce measures, including 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. Entergy employees achieved a total recordable incident rate of 0.49 in 2023 as compared to 0.51 in 2022 and 0.46 in 2021. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022 and 2023, although in early 2024 Entergy experienced a contractor fatality. Also in 2023, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions.
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 2021 of 63 (third quartile), in 2022 of 61 (third quartile), and in 2023 of 62 (third quartile). Although the score is nearly the same in 2023 as in 2022, Entergy has maintained improvement from the 2014 baseline. Improvement in behavioral expectations, which are the leading indicators of outcome improvements, indicates that Entergy is moving in a positive direction.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement for all employees. Entergy is committed to developing and retaining a top-performing workforce that reflects the rich diversity of the communities it serves. In 2021, Entergy established a new Diversity and Workforce Strategies organization to serve as a center of excellence for workforce development, talent attraction/pipeline development, and organizational health and diversity. The organization supports Entergy’s actions to strengthen our partnerships with colleges and vocational-technical schools for a more viable pipeline of future talent while expanding efforts to increase employee engagement and cultivate an inclusive culture with high performance. Entergy continues to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices, and procedures, aligning Employee Resource Group goals to business objectives, growing its DIB Champion network, ensuring that Entergy’s leadership development programs support all employees, 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 highly qualified, 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, proxy statements, and amendments to such filings. 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 https://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, https://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations, and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in XBRL format); proxy statements; and any amendments to such filings. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its internet site solely for the information of investors and does not intend the address to be an active link. Notwithstanding this reference or any references to the website in this report, the contents of the website are not incorporated into this report.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Item 1A. Risk Factors
See “RISK FACTORS SUMMARY” in Part I, Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s business, financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also be required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of costs in the Utility operating companies’ and System Energy’s base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators may disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a discussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including, but not limited to, the operation and maintenance of their assets and infrastructure, including with respect to climate or environmental matters, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such
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Entergy Corporation, Utility operating companies, and System Energy
events, the quality of their customer service, including timely and accurate billing practices and ability to resolve customer complaints, and the reasonableness of the cost 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 potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, such as through “retail open access” or otherwise, they could lose customers and sales and their results of operations, financial position, or cash flows could be materially affected. Additionally, technological advances in energy efficiency and distributed energy resources are reducing the costs of these technologies and, together with ongoing state and federal subsidies, the increasing penetration of these technologies could result in reduced sales by the Utility operating companies. Such loss of sales, due to the methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating companies. Entergy and the Utility operating companies cannot predict if or when they may be subject to changes in legislation or regulation, or the extent and timing of reductions of the cost of distributed energy resources, nor can they predict the impact of these changes on their results of operations, financial position, or cash flows.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings, and sudden or prolonged increases in fuel and purchased power costs could lead to increased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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Entergy Corporation, Utility operating companies, and System Energy
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 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. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or increase 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. Additionally, each Utility operating company’s continued participation in MISO may be affected by the outcomes of proceedings at their respective retail regulators regarding the realized and expected costs and benefits associated with such Utility operating company’s ongoing participation in MISO.
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.
The MISO tariff provisions governing the rights and obligations associated with the resource adequacy construct provided under the MISO tariff are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. As an example, MISO recently has made
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
changes to its capacity accreditation methodology for thermal resources which emphasizes performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now embarking on a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources. Due to their magnitude and, with respect to the changes already made, the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, a large volume of parties and individual generation resources are presently seeking to interconnect to the transmission system MISO administers and over which MISO exercises functional control. Due to the resources and time required to study and evaluate these numerous interconnection requests, including the effects of speculative requests and requests that are withdrawn at late stages of the process, the current MISO interconnection queue to review new requests is subject to significant delays or periods in which MISO does not accept new interconnection requests. These delays present risks to the Utility operating companies and their ability to develop and procure new generation resources to serve their respective loads.
For additional information on MISO regulation and the Utility operating companies’ membership in MISO, see “FederalRegulation of the Utility – Transmission and MISO Markets”section of Part I, Item 1.
Entergy’s and the Utility operating companies’ business, results of operations, and financial condition could be adversely affected by events beyond their control, such as public health crises, natural disasters, geopolitical tensions, or other catastrophic events.
Entergy and the Utility operating companies could be adversely affected by various events beyond their control, including, without limitation, public health crises, natural disasters, geopolitical tensions and other political instability, or other catastrophic events. Any of the foregoing, whether occurring locally, nationally, or globally, and the resulting effects thereof could lead to disruption of the general economy, impacts on the customers of the Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, due to, among other things:
•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;
•adverse impacts on liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense;
•delays in regulatory proceedings;
•regulatory outcomes that require the Utility operating companies to postpone planned investments and otherwise reduce costs due to, for example, the impact of a public health crises or such other catastrophic events on their customers;
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
•workforce availability challenges, including, for example, from infections, health, or safety issues resulting from a public health crisis;
•increased storm recovery costs;
•increased cybersecurity risks as a result of many employees telecommuting;
•volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities on favorable terms), which could in turn, cause a decrease in the value of its defined benefit pension or decommissioning trust funds;
•adverse impacts on Entergy’s credit metrics or ratings;
•governmental mandates in response to any such event; or
•other adverse impacts on their ability to execute on business strategies and initiatives.
To the extent any of these events occur, the business, results of operations, and financial condition of Entergy and the Utility operating companies could be adversely affected.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.
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, droughts, wildfires, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and typically do not have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales, such as 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.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 the end of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements, supply chain disruptions, limitations or bans on importation of uranium or uranium products from foreign countries, evolving geopolitical conditions such as the wars between Russia and Ukraine and Israel and Hamas, the Nigerien coup, or shifting trade arrangements or sanctions 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 inherent market uncertainties, as well as uncertainties arising from geopolitical conflicts, 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 uninterrupted 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 or service providers to continue to supply fuel or provide such services at acceptable prices or at all. While such suppliers have performed as expected to date, the future inability of suppliers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene in pending proceedings, which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the
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Entergy Corporation, Utility operating companies, and System Energy
change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for certain of the Utility operating companies and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of the Yucca Mountain repository 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 is in partial breach of 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which as of January 1, 2024 is $500 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 $165.9 million per reactor. With 95 reactors currently participating, this translates to a total public liability cap of approximately $15.8 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to 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 $165.9 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is approximately $830 million). The retrospective premium payment is currently limited to approximately $25 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $165.9 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of April 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or if funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, 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, and Notes 9 and 16 to the financial statements.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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.
Business Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. The occurrence of one or more contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown or unforeseen events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of high interest rates and inflation, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm or climate risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.
The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.
As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their businesses. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy’s safety culture or work environment; inability to meet their climate or human capital strategy goals, or failure to demonstrate meaningful progress toward such goals; inability to keep their electricity rates stable; inability to provide quality customer service, including timely and accurate billing; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks, data breaches or physical- or cyber- security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.
Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, investors, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with its ability to attract and retain a qualified, inclusive, and diverse workforce, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy’s future cash flows, and this legislation and pending interpretive guidance could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.
Based on initial IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next two to four years.
The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the 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 2023, 2022, 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. For further discussion of the effects of the Inflation Reduction Act of 2022, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities, which judgment may prove to be incorrect or may be disputed by regulators or 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and 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 the realization of any anticipated benefits from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including achieving Entergy’s climate goals and commitments, which are subject to business, regulatory, economic, shareholder activism 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, each of Entergy Louisiana and Entergy New Orleans have entered into purchase and sale agreements to sell their respective regulated natural gas local distribution company businesses to a third-party. 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 disruptions, import tariffs, and other 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 acquisition or disposition of a business could divert management’s attention from other business concerns;
•Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
•Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely and cost-effective manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels and power generation facilities, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
Entergy relies on a large and changing workforce, including employees, contractors, and temporary staffing. Certain factors, such as an aging workforce, mismatching of skill sets for current and future needs, failing to appropriately anticipate future workforce needs, workforce impacts from public health concerns, challenges competing with other employers offering fully remote or more flexible work options, rising salary and other labor costs, unavailability of contract resources, and labor disputes and work disruptions 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. 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 specialized 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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or the achievement of voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and has proposed regulations for new,
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. Various states and regions of the U.S. have taken action to establish greenhouse gas limitations and trading programs. In Louisiana, the LPSCformer Office of the Governor announced in 2020 the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050, while in 2021, the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units and solar facilities) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing Entergy’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or inability to meet Entergy’s voluntary climate commitments, could negatively impact Entergy’s reputation or inhibit Entergy’s ability to pursue its decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.
Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s Utility operating companies, their suppliers, or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy that exceeds Entergy’s or its Utility operating companies’ ability to add lower carbon or carbon-free capacity, load growth, potential tariffs, carbon policy and regulation at the federal or state level, including mandates related to reliability standards, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, floods, 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.
Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is pursuing 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 significant weather events, to mitigate the cost of restoration of the electric system after major storms or other significant events, to enable more rapid restoration of electricity after major storm or other significant adverse events, and to deliver electricity to critical customers more immediately after such events. These plans are generally subject to approval by the Utility operating companies’ retail regulators and may not be approved in full or at all. 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.
Additionally, prolonged drought conditions and shifting weather patterns resulting from climate change as well as, among other things, buildup of dry vegetation in areas severely impacted by drought may increase the risk of severe wildfire events within the Utility operating companies’ service areas. Catastrophic wildfires occurring in the Utility operating companies’ service areas could give rise to large damage claims against Entergy or its subsidiaries for fire-related losses alleged to be the result of utility practices and/or the failure of electric and other utility equipment and could also cause Entergy or its subsidiaries to suffer reputational harm or face a more challenging operating, political and regulatory environment.
These and other physical changes could result in, among other things, changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.
A decline in the continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water
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Entergy Corporation, Utility operating companies, and System Energy
availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, saltwater intrusion, and the potential impacts of climate change on the availability of water resources may cause water use restrictions that affect Entergy and its subsidiaries.
The Utility operating companies, System Energy, and Entergy’s non-utility operations may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-utility operations.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 Entergy’s non-utility business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-utility business.
The hedging and risk management practices of the Utility operating companies and Entergy's non-utility 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 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 benefits 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 has affected and 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 benefits 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 benefits plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which Entergy and the Registrant Subsidiaries operate have
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Entergy Corporation, Utility operating companies, and System Energy
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 and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems, including disruptions affecting other third parties ultimately connected to Entergy and its subsidiaries or their suppliers through the transmission grid, may adversely affect Entergy’s business and results of operations.
As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors or other third parties interconnected through the grid. Like many businesses and operators of critical infrastructure, Entergy and its subsidiaries and their third-party suppliers have in the past and, will in the future, continue to be subject to cyber attacks, cybersecurity threats and attempts to compromise and penetrate the information technology systems of Entergy and its subsidiaries and disrupt their operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An attack could affect Entergy’s or its subsidiaries’ 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, including threats fueled by artificial intelligence, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. In addition, the prevalent use of smartphones, tablets, and other wireless devices, as well as ongoing remote or hybrid work-from-home arrangement for a significant portion of Entergy’s employees and those of its contractors and vendors may also heighten these risks. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors or other third parties interconnected through the grid, 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. We cannot anticipate, detect, or implement fully preventive measures against all cybersecurity threats.
Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Registrant Subsidiaries’ business, financial condition, results of operations or reputation. Although Entergy and the Registrant
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Entergy Corporation, Utility operating companies, and System Energy
Subsidiaries purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these incidents. Such incidents may also expose Entergy to an increased risk of litigation (and associated damages and fines). For information on our cybersecurity risk management, strategy, and governance, see “Item 1C. Cybersecurity” in Part I, Item 1C.
Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The global economic cost to insurers resulting from cyber attacks, natural disasters, and other catastrophic events, in addition to an increased focus on climate issues, could have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles, higher premiums, and more restrictive terms and conditions. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.
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 continued inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.
(Entergy Corporation and System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to
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Entergy Corporation, Utility operating companies, and System Energy
System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy when required.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas) 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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 filingUnit Power Sales Agreement, and two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 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, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy when required. System Energy and its debt securities have been subject to downgrade by rating agencies in the past, most recently in May 2023. Any further downgrade by one or more rating agencies could adversely affect the market prices of System Energy’s debt securities and otherwise adversely affect System Energy’s financial condition.
In addition, an order requiring System Energy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy’s existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy’s financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.
These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Notes 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
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Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
Entergy’s non-utility operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy’s non-utility operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-utility operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy’s non-utility operations include legal entities that meet the definition of a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC’s orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.496 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.
Entergy’s non-utility operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market has imposed, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-utility operations’ generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-utility operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single joint,clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy’s non-utility operations’ results of operations, financial condition, and liquidity could be materially affected.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy’s common stock. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy 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, LLC 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, LLC and are therefore subject to prior payment of distributions on its preferred securities.
The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse, and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error, or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.
The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury, and fines and/or penalties and may adversely affect our reputation.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Risk Management and Strategy
Entergy and the Registrant Subsidiaries maintain a security-risk-management system with defined roles, duties, governance, and accountability. Under this physical- and cyber-risk model, Entergy and the Registrant Subsidiaries streamline security into a centralized program. The Chief Security Officer (CSO) is responsible for
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
establishing the security and reliability risk strategy, setting policies, monitoring controls and compliance, providing support activities, and reporting on the security program. The Chief Information Security Officer (CISO) is responsible for establishing the cybersecurity strategy and implementing physical and cyber security systems for the security program. The Chief Ethics & Compliance Officer works with the CSO to address requirements of external security-related regulations, and where applicable, incorporate them into business policies. Management is responsible for identifying and managing risk directly through execution of the security program and compliance with security policies. Entergy and the Registrant Subsidiaries’ risk management model addresses compliance with certain regulatory constructs, such as the NERC Reliability Standards, the NRC Code of Federal Regulations, the Payment Card Industry Data Security Standard, and the Health Insurance Portability and Accountability Act, among other regulations. Entergy and the Registrant Subsidiaries’ risk management model continuously evolves to improve and implement protections, controls, and monitoring to mitigate risks to their part of North America’s electric grid, to protect sensitive information, and to maintain secure business operations. Entergy and the Registrant Subsidiaries manage cybersecurity threats as an enterprise risk with close coordination and information sharing with its federal, state, and local partners. Entergy and the Registrant Subsidiaries also engage with local, state, and federal law enforcement agencies on initiatives to share threat information and participate in a wide range of industry collaborations and classified briefings on cybersecurity developments and evolving risks.
Entergy and the Registrant Subsidiaries maintain access-management controls, including a layered multi-factor authentication process for network and system access, and a defense-in-depth security ecosystem that includes advanced threat detection from independent third parties and federal agencies, security logging and monitoring, and independent third-party penetration and vulnerability assessments. Relevant employees and contractors must complete cybersecurity trainings periodically to heighten security and threat awareness, promote best practices, and meet regulatory requirements. Additional multi-layered prevention and detection processes and technologies to mitigate and minimize the effects of cybersecurity risks include email security, continuous monitoring, vulnerability scanning, anti-virus and anti-malware software, backups and recovery strategy, network segregation, third-party security, and information protection.
Entergy and the Registrant Subsidiaries have incorporated certain cyber-specific response protocols and procedures into their Entergy Incident Management System framework for responding to emergency incidents. This includes the Entergy Incident Response Team Plan, which outlines Entergy’s procedures, steps, and responsibilities for preparing for, detecting, containing, and recovering from an incident. The plan details the roles and responsibilities of Entergy’s officers who would be engaged in such a response to an emergency incident, including key questions to be addressed, critical decision points, and sources of key information to support decision-making. Senior management and the Emergency Incident Response Team periodically review and drill on the plan.
As cybersecurity risks continue to evolve with multiple threat vectors, Entergy and the Registrant Subsidiaries maintain a comprehensive security strategy to keep current with the changing threats. To inform this effort, Entergy and the Registrant Subsidiaries utilize the National Institute of Standards and Technology Cybersecurity Framework, which consists of standards, guidelines, and best practices to manage cybersecurity risk across the enterprise. A risk-based approach is used to direct security initiatives to the most significant risks and provide the most value in terms of risk reduction and protection. Entergy and the Registrant Subsidiaries use a vendor risk management program to assess and monitor security risks that arise from third-party vendors. In addition, Entergy and the Registrant Subsidiaries utilize technology and threat intelligence services to assess and continuously monitor the cybersecurity risk of key vendors, as identified through the vendor risk management program.
While Entergy and the Registrant Subsidiaries have experienced cybersecurity incidents, except as otherwise summarized above or discussed elsewhere in this report, the risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected them including their business strategy, results of operations, or financial condition. See “Item 1A. Risk Factors” in Part I, Item 1A for a detailed description of the risks related to cybersecurity.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Corporate Governance
The Board of Directors is responsible for oversight of the identification, management, and mitigation of enterprise-wide risk, including cybersecurity risk. The Audit Committee has the primary responsibility for overseeing risk management, including oversight of cybersecurity risk management practices and performance. The Audit Committee generally receives reports at each regular quarterly meeting provided by the Chief Information Officer, the CSO, the CISO, and the General Auditor on the cybersecurity management program. The reports focus on the programs and protocols in place to mitigate cybersecurity risks, led by the CSO. Among other things, the reports may include: recent cyber risk and cybersecurity developments; industry engagement activities; legislative and regulatory developments; cyber-risk governance and oversight; selected cyber risk metrics and activities; cyber risk incident response plans and strategies; cybersecurity drills and exercises; assessments by third party experts and Internal Audit; and major projects and initiatives.
While the Board of Directors and Audit Committee oversee cybersecurity risk management, Entergy’s management is responsible for managing cybersecurity risk. Entergy and the Registrant Subsidiaries’ security-risk-management system, as discussed above, is comprised of a three lines of defense model to enhance risk management efforts and define roles in the security program. The first line of defense, comprised of business units performing operational functions, including the CISO, is responsible for identification and management of security and reliability risks directly through design, implementation, and execution of control activities. The second line of defense, comprised of the CSO and Chief Security Office, performs and supports security and reliability risk management and governs and oversees the execution of security and reliability controls by the first line of defense. Ownership of specific security operations may migrate from a business unit in the first line of defense to the second line of defense, as determined to be appropriate by the Chief Security Office. The third line of defense, which includes Internal Audit, independent third parties, and certain regulatory constructs, such as the NERC Reliability Standards and the NRC Cyber Rule, provides assurance of selective actions taken by the first and second lines of defense to senior management and the Board of Directors.
Entergy’s CSO is responsible for overseeing physical, cyber, and reliability risk, including governance, compliance, and threat intelligence. The CSO’s background includes serving as the Global Lead Business Information Security Officer for a multinational pharmaceutical and biotechnology company, Vice President of Cybersecurity Solutions for an international consulting firm, and an operations manager for a multinational technology company. The CSO is also a former intelligence officer in the U.S. Marine Corps, with experience in the Fleet Marine Force, Joint Staff J-2/Defense Intelligence Agency, and Headquarters Marine Corps Command, Control, Communications, and Computers (C4I). The CSO participated in numerous exercises and crisis operations during his time in the military. The CSO is a certified Information Security Manager from the Information Systems Audit and Control Association and a certified Information Privacy Manager from the International Association of Privacy Professionals. The CSO also completed the Harvard Kennedy School Executive Education Program in Cybersecurity and the FBI Domestic Security Executive Academy.
Entergy’s CISO is responsible for enterprise strategic and operational cybersecurity, physical security systems, and regulatory compliance. The CISO oversees investments in tools, resources, and processes that allow for the continuous improvement and maturity of Entergy’s cybersecurity posture. The CISO has expertise spanning more than 25 years in the realm of information technology, information security, and cyber/physical security management. The CISO’s background includes serving as the Vice President and Chief Information Security Officer for an electric utility with responsibility for enterprise cybersecurity covering corporate, electric, nuclear, and gas operations. Additionally, the CISO served as the Chief Security Officer for the Electric Reliability Council of Texas with overall responsibility for its cybersecurity, physical security, and emergency management programs. Her previous experience includes multiple technical, managerial, and strategic roles within industries ranging from energy, telecommunication, software development, and cybersecurity consulting. The CISO is a Certified Information Systems Security Professional, Certified Information Security Manager, and Certified in Risk and Information Systems Control.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
In the event of a suspected or actual cybersecurity incident, the Security Incident Response Team (SIRT), which includes the CISO, has primary responsibility for initial identification and evaluation of potential business impacts and escalation of the incident’s severity classification using pre-established criteria with a specified communication matrix and escalation thresholds. The Security Incident Commander, which role is served by rotating leaders in the CISO organization, provides tactical leadership and oversight management at the cross-functional level for the incident. The SIRT remains engaged throughout the incident response lifecycle, including detection and analysis, containment, eradication and recovery, and post-incident remediation, and coordinates with the impacted business functions, if warranted. Once a cyber incident is confirmed, the SIRT is responsible for maintaining situational awareness and continuous monitoring of the need for escalation or de-escalation of the incident’s severity classification. As certain escalation thresholds are exceeded, additional levels of management notification are required by the SIRT, including notification of and recurring communication with Entergy’s Incident Response Team, which includes the Chief Executive Officer, the Chief Operating Officer, the CSO, other executive management, and members of the affected business functions. Depending upon the facts, analysis, materiality, and anticipated or current impacts, the Chief Executive Officer and the General Counsel will determine the timing and cadence for communication of the cyber incident with the Board of Directors or Audit Committee.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2023 Compared to 2022
Net Income
Net income increased $104 million primarily due to a $159.6 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, higher retail electric price, lower other operation and maintenance expenses, and higher other income. The increase was partially offset by write-offs of $78.4 million ($58.8 million net-of-tax) in third quarter 2023 as a result of Entergy Arkansas’s approved motion to forgo recovery related to the 2013 ANO stator incident, higher interest expense, lower volume/weather, and higher depreciation and amortization expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2023 to 2022:
| | | | | |
| Amount |
| (In Millions) |
| 2022 operating revenues | $2,673.2 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (75.0) | |
| Volume/weather | (31.4) | |
| Retail electric price | 79.6 | |
| 2023 operating revenues | $2,646.4 | |
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 the effect of less favorable weather on residential sales and a decrease in weather-adjusted residential usage, partially offset by an increase in industrial usage. The increase in industrial usage is primarily due to an increase in demand from small industrial customers and 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 evaluation reportrates effective January 2023. See Note 2 to the financial statements for further discussion of the 2022 formula rate plan filing.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Gulf States Louisiana’sArkansas for the years ended December 31, 2023 and 2022 are as follows:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | | |
| Residential | 7,610 | | | 8,147 | | | (7) | |
| Commercial | 5,584 | | | 5,615 | | | (1) | |
| Industrial | 9,095 | | | 8,493 | | | 7 | |
| Governmental | 192 | | | 218 | | | (12) | |
| Total retail | 22,481 | | | 22,473 | | | — | |
| Sales for resale: | | | | | |
| Associated companies | 2,218 | | | 1,906 | | | 16 | |
| Non-associated companies | 5,777 | | | 6,520 | | | (11) | |
| Total | 30,476 | | | 30,899 | | | (1) | |
See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $17.1 million in compensation and benefits costs primarily due toa decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a revision to estimated incentive compensation expense in first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
•a decrease of $10.5 million in transmission costs allocated by MISO;
•the effects of recording a final judgment in first quarter 2023 to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $10.3 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $9.6 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022.
The decrease was partially offset by:
•an increase of $10.4 million in contract costs related to operational performance, customer service, and organizational health initiatives;
•an increase of $9.2 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023;
•an increase of $5.2 million in nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022 and higher nuclear labor costs; and
•several individually insignificant items.
Asset write-offs includes the effects of Entergy Arkansas forgoing recovery of identified costs resulting from the 2013 ANO stator incident. In third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $68.9 million and the undepreciated balance of $9.5 million in capital costs related to the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
ANO stator incident. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income increased primarily due to:
•higher interest earned on money pool investments;
•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023; and
•a decrease in charitable donations in 2023 as compared to 2022.
Interest expense increased primarily due to the issuance of $425 million of 5.15% Series mortgage bonds in January 2023 and higher interest accrued on spent nuclear fuel disposal costs.
The effective income tax rates were (33.3%) for 2023 and 21.6% for 2022. 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.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $5,278 | | | $12,915 | | | $192,128 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 941,021 | | | 699,732 | | | 549,216 | | |
| Investing activities | (1,032,952) | | | (852,794) | | | (898,193) | | |
| Financing activities | 90,285 | | | 145,425 | | | 169,764 | | |
| Net decrease in cash and cash equivalents | (1,646) | | | (7,637) | | | (179,213) | | |
| | | | | | |
| Cash and cash equivalents at end of period | $3,632 | | | $5,278 | | | $12,915 | | |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2023 Compared to 2022
Operating Activities
Net cash flow provided by operating activities increased $241.3 million in 2023 primarily due to:
•lower 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;
•higher collections from customers;
•the refund of $41.7 millionreceived from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. The refund was subsequently applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;
•a decrease of $38.5 million in pension contributions in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and
•$23.2 million in proceeds received from the DOE in April 2023 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.
The increase was partially offset by:
•the timing of payments to vendors;
•an increase of $25.4 million in storm spending in 2023 as compared to 2022; and
•an increase of $22.1 million in interest paid.
Investing Activities
Net cash flow used in investing activities increased $180.2 million in 2023 primarily due to:
•an increase of $122.9 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023;
•an increase of $86.6 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Arkansas’s transmission system; and
•an increase of $43.2 million as a result of fluctuations in nuclear fuel activity due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
The increase was partially offset by:
•a decrease of $38.3 million in nuclear construction expenditures primarily due to decreased spending on various nuclear projects in 2023;
•$17.9 million in proceeds received from the DOE in April 2023 resulting from litigation regarding spent nuclear fuel storage costs that were previously recorded as plant. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $14.1 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Financing Activities
Net cash flow provided by financing activities decreased $55.1 million in 2023 primarily due to:
•an increase of $331 million in common equity distributions paid in 2023 in order to maintain Entergy Arkansas’s capital structure;
•the repayment, at maturity, of $250 million of 3.05% Series mortgage bonds in June 2023;
•the issuance of $200 million of 4.20% Series mortgage bonds in March 2022;
•the repayment, at maturity, of $40 million of 3.17% Series M notes by the Entergy Arkansas nuclear fuel company variable interest entity in December 2023; and
•money pool activity.
The decrease was partially offset by:
•the issuance of $425 million of 5.15% Series mortgage bonds in January 2023;
•the issuance of $300 million of 5.30% Series mortgage bonds in August 2023;
•net long-term borrowings of $70.2 million in 2023 as compared to net repayments of $4.8 million in 2022 on the nuclear fuel company variable interest entity’s credit facility; and
•an increase of $61.3 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Louisiana’s 2014Arkansas’s payable to the money pool decreased $35.4 million in 2023 compared to increasing by $40.9 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Arkansas is primarily due to the net issuance of long-term debt in 2023.
| | | | | | | | | | | |
| | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 55.5 | % | | 52.5 | % |
| Effect of subtracting cash | — | % | | — | % |
| Net debt to net capital (non-GAAP) | 55.5 | % | | 52.5 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced 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.
| | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $1,090 | | | $355 | | | $240 | |
| Transmission | 135 | | | 85 | | | 80 | |
| Distribution | 415 | | | 535 | | | 480 | |
| Utility Support | 65 | | | 65 | | | 65 | |
| Total | $1,705 | | | $1,040 | | | $865 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027-2028 | | After 2028 |
| | (In Millions) |
| Long-term debt (a) | $546 | | | $233 | | | $835 | | | $619 | | | $5,514 | |
| Operating leases (b) | $17 | | | $16 | | | $14 | | | $15 | | | $5 | |
| Finance leases (b) | $5 | | | $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 Arkansas currently expects to contribute approximately $55.1 million to its qualified pension plans and approximately $529 thousand to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas has $34.5 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Walnut Bend Solar
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations were conducted, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022. In April 2023, Entergy Arkansas filed an application for an amended certificate of environmental compatibility and public need with the APSC seeking approval by June 2023 for the updates to the cost and schedule that were previously approved by the APSC. In June 2023, Entergy Arkansas, the APSC general staff, and the Arkansas Attorney General filed a unanimous settlement supporting that the approval of the Walnut Bend Solar facility is in the public interest based on the terms
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
in the settlement, including the treatment for the production tax credits associated with the facility. In July 2023, after requesting further testimony and purporting to modify several terms in the settlement and upon rehearing, the APSC approved the settlement largely on the terms submitted, including a 30-year amortization period for the production tax credits. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024, at which time a substantial completion payment of approximately $20 million is expected.
West Memphis Solar
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. In March 2023 the APSC approved Entergy Arkansas’s supplemental application. The project is currently expected to achieve commercial operation by the end of 2024.
Driver Solar
In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas’s petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation as early as mid-2024.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy system money pool;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations,
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | | 2020 |
| (In Thousands) |
| ($145,385) | | ($180,795) | | ($139,904) | | $3,110 |
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 2028. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2024. 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, 2023, 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, 2023, $5.8 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 2025. As of December 31, 2023, $70.2 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 April 2025 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 April 2025. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Retail Rates
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year operations.2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The joint evaluation report was filed in September 2015 and reflected anfiling showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year was 8.22% resulting in a revenue deficiency of 9.09%. As such, no$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 to base formula rate plan revenue was required. The following adjustments were required under$88.2 million. By operation of the formula rate plan, however:Entergy Arkansas’s recovery of the revenue requirement is subject to a decreasefour 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-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 capacity mechanismprovisions 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 LouisianaArkansas’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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
of return on common equity for the 2022 projected year was 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 was $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 was 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 was $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 was limited to $72.1 million. In December 2021 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2022.
2022 Formula Rate Plan Filing
In July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2023 projected year was 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment was $119.9 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 $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas’s overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2023.
2023 Formula Rate Plan Filing
In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment is $130.3 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 $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the cap constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement. In October 2023, Entergy Arkansas made a commitment to the APSC to make a filing to forgo its opportunity to seek recovery of the incremental fuel and purchased energy expense, among other identified costs, resulting from the ANO stator incident. As a result, in third quarter 2023, Entergy Arkansas recorded a write-off of its regulatory asset for deferred fuel of $68.9 million, which includes interest, related to the ANO stator incident. Consistent with its October 2023 commitment, Entergy Arkansas filed a motion to forgo recovery in November 2023, and the motion was approved by the APSC in December 2023. See “ANO Damage, Outage, and NRC Reviews” in Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.
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 additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 millionrate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the MISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates wereredetermined rate be implemented with the first billing cycle of December 2015, subjectApril 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to refund.the tariff. In JuneJuly 2017 the LPSC staff andArkansas Attorney General requested additional information to support certain of the costs included in Entergy Louisiana filed an unopposed joint report of proceedings, which was accepted by the LPSC in JuneArkansas’s 2017 finalizing the results of this proceeding with no changes to rates already implemented.energy cost rate redetermination.
2015 Formula Rate Plan Filing
In May 2016,March 2018, Entergy LouisianaArkansas filed its formulaannual redetermination of its energy cost rate plan evaluation report for its 2015 calendar year operations. The evaluation reportpursuant to the energy cost recovery rider, which reflected an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue was required. The following other adjustments, however, were required under the formula rate plan: an increase in the legacyrate from $0.01547 per kWh to $0.01882 per kWh. The Arkansas Attorney General filed a response to Entergy Louisiana additional capacity mechanismArkansas’s annual redetermination filing requesting that the APSC suspend the proposed tariff to investigate the amount of $14.2 million; a separate increase in legacythe redetermination or, alternatively, to allow recovery subject to refund. Among the reasons the Attorney General cited for suspension were questions pertaining to how Entergy Louisiana revenueArkansas forecasted sales and potential implications of $10 million primarilythe Tax Cuts and Jobs Act. Entergy Arkansas replied to reflect the Attorney General’s filing and stated that, to the extent there are questions pertaining to its
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 terminationTax Cuts and Jobs Act are appropriately considered in the APSC’s separate proceeding regarding potential implications of the System Agreement; an increase intax law. The APSC general staff filed a reply to the legacyAttorney General’s filing and agreed that Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflectArkansas’s filing complied with the effectsterms of the termination of the System Agreement; and an increase of $11 million to the MISOenergy cost recovery mechanism. Rates were implementedrider. The redetermined rate became effective with the first billing cycle of September 2016,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.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 2021, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease from $0.01052 per kWh to $0.00959 per kWh. The redetermined rate calculation also included an adjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.
In March 2022, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities under its jurisdiction to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC’s draft report issued in its February 2021 winter storms investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas’s emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard. In September 2023 the APSC issued an order in Entergy Arkansas's company-specific proceeding and found that Entergy Arkansas’s practices during the winter storms were prudent.
In March 2023, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.01639 per kWh to $0.01883 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2022 and a $32 million deferral related to the February 2021 winter storms consistent with the APSC general staff’s request in 2022. The under-recovered balance included in the filing was partially offset by the proceeds of the $41.7 million refund that System Energy made to Entergy Arkansas in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See “Complaints Against System Energy - Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue” in Note 2 to the financial statements for discussion of the compliance report filed by System Energy with the FERC in January 2023. The redetermined rate of $0.01883 per kWh became effective with the first billing cycle in April 2023 through the normal operation of the tariff.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. 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, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 were appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In July 2021 the D.C. Circuit issued a decision denying all of the petitions for review filed in response to the FERC’s opportunity sales orders.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC’s Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer association, filed a motion to intervene and to hold Entergy Arkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by Entergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for the Eighth District granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth District affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene. An order from the district court is pending and is anticipated in 2024.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision allows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers advocating the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC’s September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas’s appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC’s decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court’s ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.
Since the enactment of the net metering legislation, the APSC has approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and to utilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also has allowed the aggregation of accounts by net metering customers. These decisions by the APSC have created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy continues to grow as additional net metering applications are approved by the APSC.
In August 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that the statute imposing the expiration of the automatic grandfathering is not ambiguous and that the APSC does not have the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC’s order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Arkansas, sought rehearing, and the Arkansas’s Governor’s executive order limiting new rulemakings calls into question how the APSC’s order to adopt new rules may be effectuated.
In September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in October 2022 with supporting documentation as to the amount and extent of cost shifting and the manner in which they would design tariffs to recover those costs on behalf of non-net metering customers. Responses to the utility and cooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
An Arkansas law was enacted effective March 2023 that revises the billing arrangements for net metering facilities in order to reduce the cost shift to non-net metering customers. The new law also imposes a new limit of 5 MW for future net metering facilities, allows utilities to recover net metering credits in the same manner as fuel, and grandfathers certain net metering facilities that are online or in process to be online by September 2024. Entergy Arkansas joined other utilities in a motion in April 2023 to close the current APSC docket related to potential cost shifting in light of the new law, and the APSC also canceled the remaining procedural schedule in this docket in April 2023. Because of the new law, in May 2023, the APSC also closed the grandfathering rulemaking that it opened in August 2022. Under the new law, the APSC must approve revisions to the utilities’ tariffs to conform to the new law no later than December 2023. The APSC opened a new rulemaking in April 2023 to consider implementation of the as-filednew law and tariffs. In October 2023 the APSC issued new net metering rules to conform to the new law, and utilities, including Entergy Arkansas, filed revised net metering tariffs to comply with the new rules on October 16, 2023. Entergy Arkansas’s revised net metering tariff was approved by the APSC in December 2023.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy Arkansas owns and, through an affiliate, operates the ANO 1 and 2 nuclear generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy Arkansas’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 of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of either ANO 1 or 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. ANO 1’s operating license expires in 2034 and ANO 2’s operating license expires in 2038.
Environmental Risks
Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Arkansas’s financial statements in conformity with GAAP 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
accounting 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 these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position, results of operations, or cash flows.
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.
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 affected 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 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 2024 Qualified Pension Cost | | Impact on 2023 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $929 | | $26,189 |
| Rate of return on plan assets | | (0.25%) | | $2,567 | | $— |
| Rate of increase in compensation | | 0.25% | | $985 | | $4,963 |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2024 Postretirement Benefits Cost | | Impact on 2023 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | ($56) | | $3,841 |
| Health care cost trend | | 0.25% | | $217 | | $2,600 |
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 2023 was $49.5 million, including $26.1 million in settlement costs. Entergy Arkansas anticipates 2024 qualified pension cost to be $19.6 million. Entergy Arkansas contributed $54.5 million to its qualified pension plans in 2023 and estimates pension contributions will be approximately $55.1 million in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.
Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2023 was $1.9 million. Entergy Arkansas expects 2024 postretirement health care and life insurance benefit income of approximately $5.5 million. Entergy Arkansas contributed $582 thousand to its other postretirement plans in 2023 and estimates 2024 contributions will be approximately $529 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 the “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, 2023 and 2022, the related consolidated statements of income, cash flows and changes in equity (pages 336 through 340 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, 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 September 2016,Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there were several interim updatesis 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 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 APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities 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 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 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 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 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 APSC and the FERC and orders issued, 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 to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 23, 2024
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,646,396 | | | $2,673,194 | | | $2,338,590 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 514,885 | | | 640,344 | | | 347,166 | |
| Purchased power | | 257,890 | | | 201,726 | | | 280,504 | |
| Nuclear refueling outage expenses | | 59,973 | | | 53,438 | | | 51,141 | |
| Other operation and maintenance | | 737,649 | | | 754,293 | | | 687,418 | |
| Asset write-offs | | 78,434 | | | — | | | — | |
| Decommissioning | | 87,321 | | | 82,326 | | | 77,696 | |
| Taxes other than income taxes | | 141,502 | | | 136,565 | | | 127,249 | |
| Depreciation and amortization | | 400,944 | | | 386,272 | | | 361,479 | |
| Other regulatory charges (credits) - net | | (87,409) | | | (89,418) | | | (31,501) | |
| TOTAL | | 2,191,189 | | | 2,165,546 | | | 1,901,152 | |
| | | | | | |
| OPERATING INCOME | | 455,207 | | | 507,648 | | | 437,438 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 20,587 | | | 17,787 | | | 15,273 | |
| Interest and investment income | | 25,024 | | | 19,554 | | | 76,953 | |
| Miscellaneous - net | | (23,216) | | | (27,348) | | | (22,278) | |
| TOTAL | | 22,395 | | | 9,993 | | | 69,948 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 188,232 | | | 150,928 | | | 140,348 | |
| Allowance for borrowed funds used during construction | | (8,270) | | | (7,070) | | | (6,641) | |
| TOTAL | | 179,962 | | | 143,858 | | | 133,707 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 297,640 | | | 373,783 | | | 373,679 | |
| | | | | | |
| Income taxes | | (99,210) | | | 80,896 | | | 75,195 | |
| | | | | | |
| NET INCOME | | 396,850 | | | 292,887 | | | 298,484 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (5,231) | | | (4,358) | | | (18,092) | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $402,081 | | | $297,245 | | | $316,576 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $396,850 | | | $292,887 | | | $298,484 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 556,780 | | | 532,291 | | | 503,539 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (102,070) | | | 78,958 | | | 100,459 | |
| Asset write-offs | | 78,434 | | | — | | | — | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (84,428) | | | (73,579) | | | 17,682 | |
| Fuel inventory | | (6,351) | | | (252) | | | (7,081) | |
| Accounts payable | | (69,947) | | | 64,944 | | | 27,967 | |
| Taxes accrued | | 4,625 | | | 10,936 | | | 7,753 | |
| Interest accrued | | 16,554 | | | 1,708 | | | (5,637) | |
| Deferred fuel costs | | 228,021 | | | (31,009) | | | (162,458) | |
| Other working capital accounts | | (29,690) | | | (29,789) | | | (53,343) | |
| Provisions for estimated losses | | (21,039) | | | 2,914 | | | 6,915 | |
| Regulatory assets | | (6,197) | | | (120,603) | | | 142,706 | |
| Other regulatory liabilities | | 240,762 | | | (264,054) | | | 21,066 | |
| | | | | | |
| Pension and other postretirement liabilities | | (109,077) | | | (67,783) | | | (175,863) | |
| Other assets and liabilities | | (152,206) | | | 302,163 | | | (172,973) | |
| Net cash flow provided by operating activities | | 941,021 | | | 699,732 | | | 549,216 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (946,244) | | | (785,168) | | | (722,628) | |
| Allowance for equity funds used during construction | | 20,587 | | | 17,787 | | | 15,273 | |
| Nuclear fuel purchases | | (137,616) | | | (98,635) | | | (84,302) | |
| Proceeds from sale of nuclear fuel | | 32,937 | | | 37,198 | | | 16,279 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 117,123 | | | 248,191 | | | 530,628 | |
| Investment in nuclear decommissioning trust funds | | (139,280) | | | (269,497) | | | (524,783) | |
| Payment for purchase of assets | | — | | | (1,044) | | | (131,770) | |
| Change in money pool receivable - net | | — | | | — | | | 3,110 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 17,933 | | | — | | | — | |
| | | | | | |
| | | | | | |
| Decrease (increase) in other investments | | 1,608 | | | (1,626) | | | — | |
| Net cash flow used in investing activities | | (1,032,952) | | | (852,794) | | | (898,193) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,093,253 | | | 232,731 | | | 719,284 | |
| Retirement of long-term debt | | (597,720) | | | (28,521) | | | (728,917) | |
| | | | | | |
| Capital contributions from noncontrolling interest | | — | | | — | | | 51,202 | |
| | | | | | |
| Changes in money pool payable - net | | (35,410) | | | 40,891 | | | 139,904 | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (417,000) | | | (86,000) | | | (50,000) | |
| | | | | | |
| Other | | 47,162 | | | (13,676) | | | 38,291 | |
| Net cash flow provided by financing activities | | 90,285 | | | 145,425 | | | 169,764 | |
| Net decrease in cash and cash equivalents | | (1,646) | | | (7,637) | | | (179,213) | |
| Cash and cash equivalents at beginning of period | | 5,278 | | | 12,915 | | | 192,128 | |
| Cash and cash equivalents at end of period | | $3,632 | | | $5,278 | | | $12,915 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $169,173 | | | $147,060 | | | $143,561 | |
| Income taxes | | $2,705 | | | ($2,753) | | | ($18,933) | |
| Noncash investing activities: | | | | | | |
| Accrued construction expenditures | | $36,264 | | | $93,189 | | | $35,616 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $520 | | | $1,911 | |
| Temporary cash investments | | 3,112 | | | 3,367 | |
| Total cash and cash equivalents | | 3,632 | | | 5,278 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 157,520 | | | 140,513 | |
| Allowance for doubtful accounts | | (7,182) | | | (6,528) | |
| Associated companies | | 124,672 | | | 45,336 | |
| Other | | 89,532 | | | 101,096 | |
| Accrued unbilled revenues | | 117,119 | | | 116,816 | |
| Total accounts receivable | | 481,661 | | | 397,233 | |
| | | | |
| Deferred fuel costs | | — | | | 139,739 | |
| Fuel inventory - at average cost | | 57,495 | | | 51,144 | |
| Materials and supplies - at average cost | | 358,302 | | | 288,260 | |
| Deferred nuclear refueling outage costs | | 35,463 | | | 56,443 | |
| | | | |
| | | | |
| Prepayments and other | | 40,866 | | | 26,576 | |
| | | | |
| TOTAL | | 977,419 | | | 964,673 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,414,009 | | | 1,199,860 | |
| | | | |
| Other | | 801 | | | 2,414 | |
| TOTAL | | 1,414,810 | | | 1,202,274 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 14,821,814 | | | 14,077,844 | |
| | | | |
| Construction work in progress | | 340,601 | | | 417,244 | |
| Nuclear fuel | | 213,722 | | | 176,174 | |
| TOTAL UTILITY PLANT | | 15,376,137 | | | 14,671,262 | |
| Less - accumulated depreciation and amortization | | 6,002,203 | | | 5,729,304 | |
| UTILITY PLANT - NET | | 9,373,934 | | | 8,941,958 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 1,885,361 | | | 1,810,281 | |
| Deferred fuel costs | | — | | | 68,883 | |
| Other | | 21,334 | | | 18,507 | |
| TOTAL | | 1,906,695 | | | 1,897,671 | |
| | | | |
| TOTAL ASSETS | | $13,672,858 | | | $13,006,576 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $375,000 | | | $290,000 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 225,344 | | | 276,362 | |
| Other | | 215,502 | | | 310,339 | |
| Customer deposits | | 113,186 | | | 102,799 | |
| Taxes accrued | | 105,151 | | | 100,526 | |
| | | | |
| Interest accrued | | 35,370 | | | 18,816 | |
| Deferred fuel costs | | 88,282 | | | — | |
| | | | |
| Other | | 55,683 | | | 43,394 | |
| TOTAL | | 1,213,518 | | | 1,142,236 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,437,053 | | | 1,498,234 | |
| Accumulated deferred investment tax credits | | 27,270 | | | 28,472 | |
| Regulatory liability for income taxes - net | | 392,496 | | | 435,157 | |
| Other regulatory liabilities | | 759,181 | | | 475,758 | |
| Decommissioning | | 1,560,057 | | | 1,472,736 | |
| Accumulated provisions | | 58,959 | | | 79,998 | |
| Pension and other postretirement liabilities | | 8,901 | | | 118,020 | |
| Long-term debt | | 4,298,080 | | | 3,876,500 | |
| Other | | 156,673 | | | 97,650 | |
| TOTAL | | 8,698,670 | | | 8,082,525 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,739,071 | | | 3,753,990 | |
| Noncontrolling interest | | 21,599 | | | 27,825 | |
| TOTAL | | 3,760,670 | | | 3,781,815 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $13,672,858 | | | $13,006,576 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2023, 2022, and 2021 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2020 | $— | | | $3,276,169 | | | $3,276,169 | |
| Net income (loss) | (18,092) | | | 316,576 | | | 298,484 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (50,000) | | | (50,000) | |
| | | | | |
| | | | | |
| Capital contributions from noncontrolling interest | 51,202 | | | — | | | 51,202 | |
| | | | | |
| Balance at December 31, 2021 | $33,110 | | | $3,542,745 | | | $3,575,855 | |
| Net income (loss) | (4,358) | | | 297,245 | | | 292,887 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (86,000) | | | (86,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (927) | | | — | | | (927) | |
| | | | | |
| Balance at December 31, 2022 | $27,825 | | | $3,753,990 | | | $3,781,815 | |
| Net income (loss) | (5,231) | | | 402,081 | | | 396,850 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (417,000) | | | (417,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (995) | | | — | | | (995) | |
| | | | | |
| Balance at December 31, 2023 | $21,599 | | | $3,739,071 | | | $3,760,670 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2023 Compared to 2022
Net Income
Net income increased $417.5 million primarily due to the net effects of Entergy Louisiana’s formula rate plan,storm cost securitization in March 2023, including a $133.4 million reduction in income tax expense, partially offset by a $103.4 million ($76.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the one submittedsecuritization regulatory proceeding; a $179.1 million reduction in December 2016, reflecting implementationincome tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $38 million regulatory charge ($27.8 million net-of-tax) to reflect credits expected to be provided to customers; the reversal of a $105.6 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded in fourth quarter 2023, as part of the settlement of the Waterford 3 replacement steam generator project prudence review described below. In JuneEntergy Louisiana’s test year 2017 the LPSC staffformula rate plan filing; higher retail electric price; higher other income; lower other operation and Entergy Louisiana filed a joint report of proceedings, whichmaintenance expenses; and higher volume/weather. The net income increase was acceptedpartially offset by the net effects of Entergy Louisiana’s storm cost securitization in May 2022, including a $290 million reduction in income tax expense, partially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC in June 2017, finalizing the resultsancillary order issued as part of the May 2016 evaluation report, interim updates, securitization regulatory proceeding, and corresponding proceedings with no changeshigher depreciation and amortization expenses. See Note 2 to rates already implemented.
Extensionthe financial statements for further discussion of MISO Cost Recovery Mechanism Rider
In November 2016, Entergy Louisiana filed with the LPSC a request to extendstorm cost securitizations and the MISO cost recovery mechanism rider provision of its formula rate plan. In March 2017plan global settlement. See Note 3 to the LPSC staff submitted direct testimony generally supportive of a one-year extensionfinancial statements for further discussion of the MISO cost recovery mechanismresolution of the 2016-2018 IRS audit.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2023 to 2022:
| | | | | |
| Amount |
| (In Millions) |
| 2022 operating revenues | $6,338.8 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (1,368.1) | |
| Storm restoration carrying costs | (6.9) | |
| Return of unprotected excess accumulated deferred income taxes to customers | 24.6 | |
| Volume/weather | 40.8 | |
| Retail electric price | 118.6 | |
| 2023 operating revenues | $5,147.8 | |
Entergy Louisiana’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the intervenor inrevenues 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 proceeding did notrevenue variance associated with these items.
Storm restoration carrying costs represent the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
oppose an extension for this periodHurricane Ida restoration costs in May 2022 and the equity component of time. In July 2017 an uncontested joint stipulation authorizing a one-year extensionstorm restoration carrying costs recognized as part of the MISOsecuritization of Hurricane Ida restoration costs in March 2023. See Note 2 to the financial statements for discussion of the storm cost recovery mechanism rider was approved.securitizations.
2016 Formula Rate Plan Filing
In May 2017, Entergy Louisiana filed itsThe return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan evaluation reporteffective May 2018 in response to the enactment of the Tax Cuts and Jobs Act. In 2022, $24.6 million was returned to customers through reductions in operating revenues. There was no return of unprotected excess accumulated deferred income taxes to customers in 2023. There was no effect on net income as the reductions in operating revenues were offset by reductions in income tax expense. See Note 2 to the financial statements for its 2016 calendar year operations. discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The evaluation report reflected an earned returnvolume/weather variance is primarily due to the effect of more favorable weather on common equity of 9.84%. As such, no adjustmentresidential and commercial sales.
The retail electric price variance is primarily due to base formula rate plan revenue was required. Adjustments, however, were required under the formula rate plan; the 2016 formula rate plan evaluation report showed a decreaseincreases in formula rate plan revenue of approximately $16.9 million, comprised of a decrease in legacy Entergy Louisiana formula rate plan revenue of $3.5 million, a decrease in legacy Entergy Gulf States Louisiana formula rate plan revenue of $9.7 million, and a decrease in incremental formula rate plan revenue of $3.7 million. Additionally, the formula rate plan evaluation report called for a decrease of $40.5 millionrevenues, including increases in the MISO costdistribution and transmission recovery revenue requirement from the present level of $46.8 million to $6.3 million. Rates reflecting these adjustments were implemented with the first billing cycle ofmechanisms, effective September 2017, subject to refund. In2022 and September 2017 the LPSC issued its report indicating that no changes to Entergy Louisiana’s original formula rate plan evaluation report were required but reserved for several issues, including Entergy Louisiana’s September 2017 update to its formula rate plan evaluation report.
Formula Rate Plan Extension Request
In August 2017, Entergy Louisiana filed a request with the LPSC seeking to extend its formula rate plan for three years (2017-2019) with limited modifications to its terms. Those modifications include: a one-time resetting of base rates2023. See Note 2 to the midpoint of the band at Entergy Louisiana’s authorized return on equity of 9.95%financial statements for the 2017 test year; narrowingfurther discussion of the formula rate plan bandwidth from proceedings.
Total electric energy sales for Entergy Louisiana for the years ended December 31, 2023 and 2022 are as follows:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | | |
| Residential | 14,207 | | | 14,119 | | | 1 | |
| Commercial | 11,074 | | | 10,927 | | | 1 | |
| Industrial | 31,599 | | | 31,666 | | | — | |
| Governmental | 801 | | | 820 | | | (2) | |
| Total retail | 57,681 | | | 57,532 | | | — | |
| Sales for resale: | | | | | |
| Associated companies | 4,406 | | | 5,416 | | | (19) | |
| Non-associated companies | 1,534 | | | 3,423 | | | (55) | |
| Total | 63,621 | | | 66,371 | | | (4) | |
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 decreased primarily due to:
•a totaldecrease of 160 basis points$27.9 million in compensation and benefits costs primarily due to 80 basis points;lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, and a forward-looking mechanism that would allow Entergy Louisianarevision to recover certain transmission-related costs contemporaneously with when those projects begin delivering benefits to customers. Entergy Louisiana requested that the LPSC consider its request on an expedited basis,estimated incentive compensation expense in an effort to maintain Entergy Louisiana’s current cycle for implementing rate adjustments, i.e., September 2018, without the need for filing a full base rate case proceeding. Several parties have intervened in the proceedingfirst quarter 2023. See “Critical Accounting Estimates” below and all parties have been participating in settlement discussions.
Waterford 3 Replacement Steam Generator Project
Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regardNote 11 to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a needfinancial statements for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowancediscussion of $141pension and other postretirement benefits costs;
•a decrease of $25.1 million of incremental projectin transmission costs claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requestedallocated by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damageMISO. See Note 2 to the steam generators. Nevertheless,financial statements for further information on the ALJ concluded that Entergy Louisiana was liable for the conductrecovery of its contractor and subcontractor and, therefore, recommended these costs;
•a disallowancedecrease of $67$12.3 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrencenon-nuclear generation expenses primarily due to a lower scope of $2 millionwork, including during plant outages, performed in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy
2023 as compared to 2022;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•a decrease of $8.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2023 as compared to 2022, lower nuclear labor costs, and lower costs associated with materials and supplies in 2023 as compared to 2022; and
Louisiana•a decrease of $7.2 million in customer service center support costs primarily due to lower contract costs.
The decrease was partially offset by:
•an increase of $15.9 million in contract costs related to operational performance, customer service, and organizational health initiatives;
•an increase of $6.1 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023; and
•several individually insignificant items.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other regulatory charges (credits) - net includes:
•a regulatory charge of $103.4 million, recorded in first quarter 2023, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the March 2023 storm cost securitization;
•a regulatory charge of $224.4 million, recorded in second quarter 2022, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the May 2022 storm cost securitization; and
•a regulatory charge of $38 million, recorded in fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge,2023, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contained significant factual and legal errors.
In October 2016 the parties reached a settlement in this matter. The settlement was approved by the LPSC in December 2016. The settlement effectivelycredits expected to be provided for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The refund to customers of approximately $71 million as a result of the settlement approved byresolution of the LPSC was made2016-2018 IRS audit. See Note 3 to customers in January 2017. Of the $71 millionfinancial statements for further discussion of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outsidethe resolution of sharing, and $3 million through its fuel adjustment clause.the 2016-2018 IRS audit.
In addition, Entergy Louisiana had previously recordedrecords a provisionregulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income increased primarily due to:
•an increase of $48$113 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016in affiliated dividend income from affiliated preferred membership interests related to the $67storm cost securitizations;
•a $31.6 million of disallowed plant. An additional regulatory charge, of $23 million was recorded in fourthsecond quarter 2016 to reflect2022, for the effectsLURC’s 1% beneficial interest in the storm trust I established as part of the settlement. The settlement also provided that Entergy Louisiana could retainHurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida May 2022 storm cost securitization as compared to a $14.6 million charge, recorded in first quarter 2023, for the value associated with potential service credits agreed to byLURC’s 1% beneficial interest in the project contractor,storm trust II established as part of the Hurricane Ida March 2023 storm cost securitization. See Note 2 to the extent they are realizedfinancial statements for discussion of the storm cost securitizations;
•changes in decommissioning trust fund activity, including portfolio rebalancing of certain decommissioning trust funds in 2022; and
•an increase in the future. Following a review by the parties, an unopposed joint report of proceedings was filed by the LPSC staff and Entergy Louisianaallowance for equity funds used during construction due to higher construction work in May 2017 and the LPSC accepted the joint report of proceedings resolving the matter.progress in 2023.
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate formed the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. Testimony filed by the LPSC staff generally supported the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in January 2017.
Union Power Station and Deactivation or Retirement Decisions for Entergy Louisiana Plants
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by:
•a decrease of $20.6 million in the amount of storm restoration carrying costs recognized in 2023 as compared to 2022, primarily related to Hurricane Ida. See Note 2 to the financial statements for discussion of the storm cost securitizations; and
•lower interest income from carrying costs related to the deferred fuel balance.
The effective income tax rates were (19.3%) for 2023 and (23.5%) for 2022. 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.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Planned Sale of Gas Distribution Business
See the “Planned Sale of Gas Distribution Businesses” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the purchase and sale agreement for the sale of Entergy Louisiana’s gas distribution business.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $56,613 | | | $18,573 | | | $728,020 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 2,032,120 | | | 1,177,508 | | | 1,052,526 | |
| Investing activities | (3,039,456) | | | (4,707,711) | | | (3,700,199) | |
| Financing activities | 953,495 | | | 3,568,243 | | | 1,938,226 | |
| Net increase (decrease) in cash and cash equivalents | (53,841) | | | 38,040 | | | (709,447) | |
| | | | | |
| Cash and cash equivalents at end of period | $2,772 | | | $56,613 | | | $18,573 | |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2023 Compared to 2022
Operating Activities
Net cash flow provided by operating activities increased $854.6 million in 2023 primarily due to:
•a decrease of $236.7 million in storm spending primarily due to Hurricane Ida restoration efforts in 2022;
•an increase of $42.4 million in interest received primarily due to shorter-term financing interest earnings and interest on storm reserve escrow accounts. See Note 2 to the financial statements for a discussion of shorter-term financing interest earnings;
•the refund of $27.8 million received from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;
•a decrease of $9.1 million in pension contributions in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
•lower 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; and
•the timing of payments to vendors.
The increase was partially offset by lower collections from customers and an increase of $14.4 million in interest paid.
Investing Activities
Net cash flow used in investing activities decreased $1,668.3 million in 2023 primarily due to:
•an increase in investment in affiliates in 2022 due to the $3,163.6 million purchase by the storm trust I of preferred membership interests issued by an Entergy affiliate, partially offset by the $1,390.6 million redemption of preferred membership interests. See Note 2 to the financial statements for a discussion of the May 2022 storm cost securitization;
•a decrease of $727 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
•a decrease of $265.4 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2023 and decreased spending on various transmission projects in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
•$125 million of redemptions in 2023 of preferred membership interests held by the storm trust I, as part of periodic redemptions that are expected to occur, subject to certain conditions, for the preferred membership interests that were issued in connection with the May 2022 storm cost securitization. See Note 2 to the financial statements for a discussion of the May 2022 storm cost securitization and the storm trust I’s investment in preferred membership interests; and
•net receipts from storm reserve escrow accounts of $49.6 million in 2023 as compared to net payments to storm reserve escrow accounts of $293.4 million in 2022.
The decrease was partially offset by:
•an increase in investment in affiliates in 2023 due to the $1,457.7 million purchase by the storm trust II of preferred membership interests issued by an Entergy affiliate. See Note 2 to the financial statements for a discussion of the March 2023 storm cost securitization and the storm trust II’s investment in preferred membership interests;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•an increase of $110.2 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2023;
•an increase of $47.5 million as a result of fluctuations in nuclear fuel activity 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
•money pool activity.
Decreases in Entergy Louisiana’s receivables from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased $14.5 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities decreased $2,614.7 million in 2023 primarily due to:
•proceeds from securitization of $1.5 billion received by the storm trust II in 2023 as compared to proceeds from securitization of $3.2 billion received by the storm trust I in 2022;
•the repayment, at maturity, of $665 million of 0.62% Series mortgage bonds in November 2023;
•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022;
•the repayment, at maturity, of $325 million of 4.05% Series mortgage bonds in September 2023;
•the repayment, prior to maturity, of $300 million of 5.59% Series mortgage bonds in December 2023;
•an increase of $36.8 million in common equity distributions paid in 2023 in order to maintain Entergy Louisiana’s capital structure;
•the repayment, at maturity, of $20 million of 3.22% Series I notes by the Entergy Louisiana Waterford variable interest entity in December 2023; and
•money pool activity.
The decrease was partially offset by:
•a capital contribution of approximately $1.5 billion in 2023 as compared to a capital contribution of approximately $1 billion in 2022, both received indirectly from Entergy Corporation and related to the March 2023 storm cost securitization and the May 2022 storm cost securitization, respectively;
•the repayment, prior to maturity, of $435 million, a portion of the outstanding principal, of 0.62% Series mortgage bonds in May 2022;
•the repayment, at maturity, of $200 million of 3.3% Series mortgage bonds in December 2022;
•the issuance of $70 million of 5.94% Series J notes by the Entergy Louisiana Waterford variable interest entity in September 2023; and
•a decrease of $25 million in 2023 in net repayments on Entergy Louisiana’s revolving credit facility.
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 $69.9 million in 2023 compared to increasing by $226.1 million in 2022.
See Note 5 to the financial statements for details of long-term debt. See Note 2 to the financial statements for discussion of the storm cost securitizations.
2022 Compared to 2021
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Capital Structure
Entergy Louisiana’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Louisiana is primarily due to the $1.5 billion capital contribution received indirectly from Entergy Corporation in March 2023 and the net retirement of long-term debt in 2023.
| | | | | | | | | | | |
| | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 44.9 | % | | 53.0 | % |
| | | |
| | | |
| Effect of subtracting cash | 0.0 | % | | (0.1 | %) |
| Net debt to net capital (non-GAAP) | 44.9 | % | | 52.9 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Louisiana also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced 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.
| | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $435 | | | $805 | | | $780 | |
| Transmission | 520 | | | 775 | | | 1,220 | |
| Distribution | 775 | | | 790 | | | 755 | |
| Utility Support | 100 | | | 95 | | | 95 | |
| Total | $1,830 | | | $2,465 | | | $2,850 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes investments in generation projects to modernize, decarbonize, and diversify Entergy Louisiana’s portfolio; investments in River Bend and Waterford 3; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027-2028 | | After 2028 |
| | (In Millions) |
| Long-term debt (a) | $1,719 | | | $659 | | | $983 | | | $1,419 | | | $9,635 | |
| Operating leases (b) | $17 | | | $14 | | | $11 | | | $13 | | | $4 | |
| Finance leases (b) | $6 | | | $5 | | | $4 | | | $6 | | | $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 $48.4 million to its qualified pension plans and approximately $15 million to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Louisiana has $128.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy 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 termwholly-owned subsidiary of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station,Entergy Utility Holding Company, LLC, Entergy Louisiana agreed to makepays distributions from its earnings at a filingpercentage determined monthly.
2021 Solar Certification and the Geaux Green Option
In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to review its decisionsprovide $242 million in net benefits to deactivate Ninemile 3Entergy Louisiana’s customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and Willow Glen 2(iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and 4the Elizabeth Facility have estimated in service dates in 2024, and its decisionthe Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025, but are now expected to retire Little Gypsy 1.be no sooner than 2027. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.
The proposed Rider GGO is a voluntary rate schedule that will enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the resources. Because subscription fees from Rider GGO participants are expected to help offset the cost of the resources, the design of Rider GGO also preserves the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and capacity benefits of locally-sited solar generation at a discounted price.
In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Louisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of Rider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparties to the Vacherie and St. Jacques facilities regarding amendments to the respective agreements to address the impact of the St. James Parish ordinance, and the facilities are expected to reach commercial operation no sooner than 2027, depending upon agreement by the parties on the terms of the amendments. In September 2023, Entergy Louisiana reported to the LPSC that it also entered into amended agreements related to the Sunlight Road and Elizabeth facilities. Both facilities are still expected to achieve commercial operation in 2024.
2022 Solar Portfolio and Expansion of the Geaux Green Option
In February 2023, Entergy Louisiana filed an application with the LPSC seeking certification of the Iberville/Coastal Prairie facility, which will provide 175 MW of capacity through a PPA with a third party, and the Sterlington facility, a 49 MW self-build project located near the deactivated Sterlington power plant (the 2022 Solar Portfolio). Entergy Louisiana is seeking to include these resources within the portfolio supporting the Rider GGO
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
rate schedule to help fulfill customer interest in access to renewable energy. Entergy Louisiana has requested the costs of these facilities, as offset by Rider GGO revenues, be deemed eligible for recovery in accordance with the terms of the formula rate plan and fuel adjustment clause rate mechanisms that exist at the time the facilities are placed into service. In January 2016,2024, the parties filed an uncontested stipulated settlement agreement on the key issues in the case, which stated that the 2022 Solar Portfolio should be constructed, found that Entergy Louisiana’s proposed cost recovery mechanisms were appropriate, and confirmed the resources’ eligibility for inclusion in Rider GGO. The settlement was approved by the LPSC in January 2024. The Sterlington facility is expected to achieve commercial operation in January 2026.
Alternative RFP and Certification
In March 2023, Entergy Louisiana made its compliancethe first phase of a bifurcated filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the current RFP and certification process allows. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing, which contains the details of the proposal for the alternative competitive procurement process and the information necessary to support certification, was filed in May 2023. In addition to the acquisition of up to 3 GW of solar resources, the filing also seeks approval of a new renewable energy credits-based tariff, Rider Geaux ZERO. Several parties have intervened, and a procedural schedule was established in May 2023 with a hearing scheduled for March 2024. In October 2023 the LPSC. Entergy Louisiana, LPSC staff and intervenors participated in a technical conference in March 2016 wherefiled testimony, with the LPSC staff supporting the amount of solar resources to be acquired and the alternative RFP process. The LPSC staff also supported, subject to certain recommendations, the proposed framework for evaluation and certification of the solar resources by the LPSC and the proposed tariff.
System Resilience and Storm Hardening
In December 2022, Entergy Louisiana presented informationfiled an application with the LPSC seeking a public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the program’s costs. Phase I reflects the first five years of a ten-year resilience plan and includes investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2023 a procedural schedule was established with a hearing scheduled for January 2024. The LPSC staff and certain intervenors filed direct testimony in August, September, and October 2023. The LPSC staff filed cross-answering testimony in October 2023. The testimony largely supports implementation of some level of accelerated investment in resilience, but raises various issues related to the magnitude of the investment, the cost recovery mechanism applicable to the investment, and the ratemaking for the investment. In January 2024 the hearing in this matter was rescheduled to April 2024.
The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC staff issued a draft rule in the rulemaking proceeding related to a requirement to file a grid resilience plan. The procedural schedule entered in the rulemaking proceeding contemplated adoption of a final rule in October 2023, but this did not occur, and a new date has not been set. The LPSC also has pending rulemakings addressing issues related to pole viability and grid maintenance practices. In December 2023, in those rulemakings, the LPSC staff issued a report and recommendation proposing to impose significant new reporting and compliance obligations related to jurisdictional utilities’ distribution and transmission operations, including new obligations related to grid hardening plans, pole inspections, pole replacement, vegetation management, storm restoration plans, new reliability metrics, software for handling customer complaints and complaint resolution, required use of drone technology, and new penalties and incentives for reliability performance and for compliance with the new obligations. In February 2024, Entergy Louisiana and other parties filed comments on the LPSC staff’s report.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Sources of Capital
Entergy Louisiana’s sources to meet its deactivation/retirement decisions for these four unitscapital 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 information on the current deactivation decisionsfinancings 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 ten-year planning horizon. Parties have requested further proceedings onnext twelve months and beyond.
Entergy Louisiana’s receivables from or (payables to) the prudencemoney pool were as follows as of December 31 for each of the decisionfollowing years.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | | 2020 |
| (In Thousands) |
| ($156,166) | | ($226,114) | | $14,539 | | $13,426 |
See Note 4 to deactivate Willow Glen 2 and 4. No party contests the prudencefinancial statements for a description of the decisionmoney pool.
Entergy Louisiana has a credit facility in the amount of $350 million scheduled to deactivate Willow Glenexpire in June 2028. 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, 2023, there were no 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, 2023, $17.1 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 2025. As of December 31, 2023, $46.6 million in loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2023, $29.5 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, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana obtained authorizations from the FERC through April 2025 for the following:
•short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
•long-term borrowings and security issuances; and
•borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
Hurricane Ida
As discussed in Note 2 to the financial statements, in August 2020 and 4 or suggests reactivationOctober 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of these units; however, issues have been raised relatedEntergy Louisiana’s service area. In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. In August 2021, Hurricane Ida caused extensive damage to Entergy Louisiana’s decisiondistribution and, to give up itsa lesser extent, transmission service rightssystems resulting in MISO for Willow Glen 2 and 4 rather than placingwidespread power outages.
In April 2022, Entergy Louisiana filed an application with the units into suspended statusLPSC relating to Hurricane Ida restoration costs. Total restoration costs for the three-year term permittedrepair and/or replacement of Entergy Louisiana’s electric facilities damaged by MISO. An evidentiaryHurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed in Note 2 to the financial statements, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023, the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the Louisiana Local Government Facilities and Community Development Authority (LCDA) to issue the bonds authorized in the LPSC’s financing order.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was held in August 2017authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and post-hearing briefsLURC-sponsored trust, Restoration Law Trust II (the storm trust II).
Pursuant to Act 293, the net proceeds of the bonds were submitted in October 2017. A decisionused by the storm trust II to purchase 14,576,757.48 Class B preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company, LLC, a majority owned indirect subsidiary of Entergy. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2023 on the preferred membership interests issued to the storm trust II. These annual dividends received by the storm trust II will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust II. Specifically, 1% of the annual dividends received by the storm trust II will be distributed to the LURC for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7.5% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.
Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of April 2023 and the system restoration charge is expected to remain in 2018.place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust II is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.
From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company loaned approximately $1.5 billion to Entergy, which was indirectly contributed to Entergy Louisiana as a capital contribution.
As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a net reduction of income tax expense of approximately $133 million, after taking into account a provision for uncertain tax positions, by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was offset by other tax charges resulting in a net reduction of income tax expense of $129 million, after taking into account a provision for uncertain tax positions. In recognition of its obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded in first quarter 2023 a $103 million ($76 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.
As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.
Nelson Industrial Steam Company
Entergy Louisiana is a partner in the Nelson Industrial Steam Company (NISCO) partnership which owns two petroleum coke generating units. In April 2023 these generating units suspended operations in the MISO market, and Entergy Louisiana currently is working to wind up the NISCO partnership, which will ultimately result in ownership of the generating units transferring to Entergy Louisiana. In November 2023 the FERC issued an order providing Section 203 of the Federal Power Act approval for any subsequent transfer of the facilities to Entergy Louisiana. Entergy Louisiana is evaluating the effect of the transaction on its results of operations, cash flows, and financial condition, but at this time does not expect the effect to be material.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
Retail Rates - Gas
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 10.45%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.
2014 Rate Stabilization Plan Filing
In January 2015,April 2022 Entergy Gulf States Louisiana filed withsubmitted for consideration a proposal to extend the infrastructure rider to address replacement of an additional 187 miles of pipe. In December 2022 Entergy Louisiana and the LPSC its gas rate stabilization planstaff submitted an uncontested settlement that extends the rider for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resulted in a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that did not affectten years beginning after the results.end of the current term of the rider in 2025. The LPSC staff’s recommended adjustments increaseextension is subject to the earned return on equitysame customer safeguards and conditions as the original term of the rider. The extension
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
allows for recovery of approximately $95 million over ten years. In February 2023, the test yearuncontested settlement was approved by the LPSC.
Storm Cost Recovery
See Note 2 to 7.24%.the financial statements for a discussion of Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.Louisiana’s filings to recover storm-related costs.
2015 Rate Stabilization Plan FilingOther
In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. In March 2016 the LPSC staff issuedopened two dockets to examine, on a generic basis, issues that it identified in connection with its report statingreview 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 2015 gas rate stabilizationconcerns giving rise to the two dockets arose as a result of its review of the structure of the Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax 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 filingfor 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 compliance with the exception of several issues that required additional information, explanation, or clarification for whichJanuary 2020. To date, the LPSC staff had reservedhas requested multiple rounds of comments from stakeholders and conducted one technical conference. Topics on which comments have been filed include full and limited retail access, demand response, sleeved power purchase agreements, and energy efficiency. Neither the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicated no outstanding issues remained in the filing.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In February 2016, Entergy Louisiana filed a motion requesting to extend the term of the gas rate stabilization plan in substantially similar form for an additional three-year term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony byLPSC or the LPSC staff have made recommendations or adopted any rules.
Entergy Louisiana andMississippi
Formula Rate Plan
Since the LPSC submittedconclusion in 2015 of Entergy Mississippi’s most recent base rate case, Entergy Mississippi has set electric base rates annually through a joint motion for hearingformula 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 uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issuedannual “look-back” evaluation. Entergy Mississippi is allowed a reportmaximum rate increase of proceedings that was presented with the parties’ stipulation4% 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 LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extensionmore traditional rate case environment or seek approval of a new formula rate plan.
In August 2012 the rate stabilization plan was approved byMPSC opened inquiries to review whether the LPSC in December 2016.
2016 Rate Stabilization Plan Filing
In January 2017, Entergy Louisiana filed withthen-current formulaic methodology used to calculate the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflected an earned return on common equity 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 6.37%. As partthis inquiry and review was for informational purposes only; the evaluation of the original filing, pursuantany recommendations for changes to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana sought to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana requested to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing sought an annual increase in revenue of $1.4 million. Following review of the filing, except for the proposed extraordinary cost recovery, the LPSC staff confirmed Entergy Louisiana’s filing was consistent with the principles and requirements of the rate stabilization plan. The extraordinary cost recovery request associated with the 2016 flood-related deferred operation and maintenance expenses incurred for gas operations was removed from the rate stabilization plan pending LPSC considerationexisting methodology would take place in a separate docket. In April 2017 the LPSC approved a joint report of proceedings and Entergy Louisiana submitted a revised evaluation report reflecting a $1.2 million annual increase in revenue with rates implemented with the first billing cycle of May 2017.
In connection with the joint report of proceedings accepted by the LPSC, in May 2017, Entergy Louisiana filed an application to initiate a separate proceeding to recover through the extraordinary cost provision of the gasgeneral rate stabilization plan the deferred operation and maintenance expenses of $1.4 million incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. The LPSC staff submitted its direct testimonycase or in the proceeding recommending recovery of $0.9 million. Entergy Louisianaexisting formula rate plan proceeding. In March 2013 the Mississippi Public Utilities Staff filed rebuttal testimony responding toits consultant’s report which noted the LPSC staff’s recommendation. The procedural schedule was suspended to allow the parties to engage in settlement negotiations, and in February 2018 the LPSC staff and Entergy Louisiana filed an unopposed settlement. If approved by the LPSC, the settlement would provide for Entergy Louisiana to recover, over ten years, the approximately $1.4 million in deferred operation and maintenance expense and related carrying charges. The settlement further provides for recovery to commence in May 2018.
2017 Rate Stabilization Plan Filing
In January 2018, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for test year ended September 30, 2017. The filing of the evaluation report for the test year 2017 reflected an earned 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
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return is belowon common equity formulas or calculations at that time. In June 2014 the earnings sharing bandMPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate stabilizationplan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans. The docket remains open.
In December 2019 the MPSC approved Entergy Mississippi’s proposed revisions to its formula rate plan to provide for a mechanism in the formula rate plan, the interim capacity rate adjustment mechanism, to recover the non-fuel related costs of additional owned capacity acquired by Entergy Mississippi as well as to allow similar cost recovery treatment for other capacity acquisitions that are approved by the MPSC. The MPSC must approve recovery through the interim capacity rate adjustment for each new resource. In addition, the MPSC approved revisions to the formula rate plan which allows Entergy Mississippi to begin billing rate adjustments effective April 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 results inrecover these costs through the establishment of a vegetation management rider.
In November 2020 the MPSC approved Entergy Mississippi’s revisions to its formula rate increaseplan providing for the realignment of $0.1 million. Dueenergy 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.
In June 2023 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to realign the recovery of certain long-term service agreement and conductor handling costs to the enactment in late-December 2017 of the Tax Cutsannual power management and Jobs Act, Entergy Louisiana did not have adequate time to reflect the effects of this tax legislation in the rate stabilization plan. As a result, Entergy Louisiana will file a supplement to thegrid modernization riders effective January 2018 evaluation report to reflect, among other things, a 21% federal corporate income tax rate. Any rate change resulting from the revised rate stabilization plan will become effective in rates in May 2018.2023.
Fuel and purchased power recoveryPurchased Power Cost Recovery
Entergy Louisiana recovers electricMississippi’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 foras of the billing month based upon12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC. The energy cost recovery riders allow interim rate adjustments depending on the level of suchover- or under-recovery of fuel and purchased energy costs.
To help stabilize electricity costs, incurred twoEntergy 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 priorof the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2 to the billing month.financial statements for a discussion of proceedings regarding recovery of Entergy Louisiana’s purchased gas adjustments includeMississippi’s storm-related costs.
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Management’s Financial Discussion and Analysis
Other
estimates
In October 2022 the MPSC adopted the Distributed Generation Rule. The Distributed Generation Rule maintains the 3% net metering participation cap. The Distributed Generation Rule grandfathers a 2.5 cents per kWh distributed generation benefits adder for 25 years and expands eligibility for the billing month2 cents per kWh low-income benefits adder to households up to 225% of the federal poverty level and grandfathers that adder for 25 years. The Distributed Generation Rule also directs utilities to make rate filings implementing up-front incentives for distributed generating systems and demand response battery systems, and to establish a public K-12 solar for schools program. In August 2023 the MPSC approved Entergy Mississippi’s proposed solar for schools rate schedule under the Distributed Generation Rule.
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. In October 2020 the City Council approved an agreement in principle filed by Entergy New Orleans that results in Entergy New Orleans forgoing its 2020 formula rate plan filing and shifting the three-year formula rate plan to filings in 2021, 2022, and 2023. In September 2023, Entergy New Orleans filed a motion seeking City Council approval of a three-year extension of Entergy New Orleans’s electric and gas formula rate plans, for filings in 2024, 2025, and 2026. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications.
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 that arisesfor deferred fuel expense arising from an annualthe monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
In April 2010Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the LPSC authorized its staffbilling month, adjusted by a surcharge or credit similar to initiate an audit of Entergy Louisiana’sthat included in the electric fuel adjustment clause, filings.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 auditprogram 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 filings to recover storm-related costs.
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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 and Purchased Power Cost Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included a reviewin base rates. Historically, semi-annual revisions of the reasonablenessfixed fuel factor have been made in March and September based on the market price of charges flowednatural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. In 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. In 2023 the Texas legislature modified the Texas Utilities Code to provide that material over- and under-recovered fuel balances are to be refunded or surcharged through interim fuel adjustments and that fuel reconciliations must be filed at least once every two years. Entergy Texas expects the fuel adjustment clausePUCT to undertake a rulemaking to effectuate the new legislation by Entergy Louisiana for the period from 2005 through 2009.end of 2024.
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 LPSC staffPUCT issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisianaan order in May 2013 inadopting the formrule 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 to be recovered through a creditpurchased power capacity rider. No Texas utility, including Entergy Texas, has exercised the option to customersrecover capacity costs under the rider mechanism, but Entergy Texas will continue to evaluate the benefits of utilizing the rider to recover future capacity costs. In 2023, the Texas legislature modified the Texas Utilities Code to permit a utility to seek pre-approval from the PUCT for a purchased power agreement of three years or more if such approval is a precondition to the effectiveness of such agreements, regardless of whether the utility intends to recover costs associated with the purchased power agreement through its fuel adjustment clause filing. In October 2016a purchased power capacity rider.
Transmission, Distribution, and Generation Cost Recovery
As discussed above, Entergy Texas has available rate riders to recover the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue torevenue requirements associated with certain incremental costs. These riders include a separate docket because the same issue was outstanding in the Entergy Gulf States Louisiana audit for the same time period. In November 2016 the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method oftransmission cost recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodologyfactor rider mechanism for the recovery of nuclear drytransmission-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 permitted 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. In 2023, the Texas Legislature modified the Texas Utilities Code to permit utilities to update their
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distribution cost recovery factors up to twice per year and to require the PUCT to issue an order on such update applications within 60 days, with a 15-day extension permitted for good cause.
In September 2019 the PUCT initiated a rulemaking to promulgate a generation cost recovery rider rule, implementing legislation passed in the 2019 Texas legislative session intended to allow electric utilities to recover generation investments between base rate proceedings. The PUCT approved the final rule in July 2020.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Texas’s filings to recover storm-related costs.
Other
In January 2022, Entergy Texas filed an application requesting approval to implement two voluntary renewable option tariffs, Rider Small Volume Renewable Option (Rider SVRO) and Rider Large Volume Renewable Option (Rider LVRO). Both tariffs are voluntary offerings that give customers the ability to match some or all of their monthly electricity usage with renewable energy credits that are purchased by Entergy Texas and retired on the customer’s behalf. Voluntary participation in either Rider SVRO or Rider LVRO and the charges assessed under the respective tariff would be in addition to the charges paid by customers under their otherwise applicable rate schedules and riders. In April 2022, Entergy Texas filed on behalf of the parties an unopposed settlement agreement supporting approval of Entergy Texas’s proposed voluntary renewable option tariffs. As part of the settlement agreement, Entergy Texas agreed to revise the cost allocation between the rate tiers of Rider SVRO and committed to collaborating with and considering the input of customers to develop an asset-backed green tariff program. The PUCT approved the settlement agreement in August 2022.
As part of its rate case application filed with the PUCT in July 2022, Entergy Texas requested approval of Schedule Green Future Option (Schedule GFO), an asset-backed green tariff that would allow Entergy Texas’s customers to voluntarily subscribe to a portion of the underlying solar facility’s capacity in exchange for energy credits. In August 2023 the PUCT approved an unopposed settlement in the proceeding that included approval of Schedule GFO.
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
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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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 time period. Beginning in 2021, System Energy implemented billing protocols to provide retail regulators with information regarding rates billed under the Unit Power Sales Agreement. Entergy cannot predict the outcome of any of these proceedings, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises generally are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas, franchises are considered to be contracts and, therefore, are governed pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas and holds non-exclusive franchises to provide electric
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service in approximately 70 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire over the period 2024-2058.
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, 2023 is indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Owned and Leased Capability MW(a) |
| Company | | Total | | CT / CCGT (b) | | Legacy Gas/Oil | | Nuclear | | Coal | | Hydro | | Solar |
| Entergy Arkansas | | 5,036 | | | 1,548 | | | 521 | | | 1,825 | | | 969 | | | 73 | | | 100 | |
| Entergy Louisiana | | 10,798 | | | 5,594 | | | 2,728 | | | 2,137 | | | 339 | | | — | | | — | |
| Entergy Mississippi | | 2,904 | | | 1,744 | | | 641 | | | — | | | 417 | | | — | | | 102 | |
| Entergy New Orleans | | 662 | | | 635 | | | — | | | — | | | — | | | — | | | 27 | |
| Entergy Texas | | 3,234 | | | 990 | | | 1,994 | | | — | | | 250 | | | — | | | — | |
| System Energy | | 1,245 | | | — | | | — | | | 1,245 | | | — | | | — | | | — | |
| Total | | 23,879 | | | 10,511 | | | 5,884 | | | 5,207 | | | 1,975 | | | 73 | | | 229 | |
(a)“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel storage costs.(assuming no curtailments) that each station was designed to utilize.
(b)Represents Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
Summer peak load for the Utility has averaged 21,775 MW over the previous decade.
The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, Entergy’s clean energy and other public policy goals, environmental regulations, and the age and condition of Entergy’s existing infrastructure.
The Utility operating companies’ long-term resource strategy (Portfolio Transformation Strategy) calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 7,963 MW of new long-term resources and the deactivation of about 4,241 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
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products, including long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:
•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. Regulatory approval was received in November 2022 and construction has commenced. The facility is expected to be in service by mid-2026;
•In March 2019, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Searcy Solar facility, sited on approximately 800 acres in White County near Searcy, Arkansas. Entergy Arkansas received regulatory approval from the APSC in April 2020, and closed on the acquisition, through use of a tax equity partnership, in December 2021. The Searcy Solar facility was placed in service in January 2022;
•In November 2018, Entergy Mississippi signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Sunflower Solar facility, sited on approximately 1,000 acres in Sunflower County, Mississippi. Entergy Mississippi received regulatory approval from the MPSC in April 2020, and the Sunflower Solar facility began commercial operation in September 2022;
•In June 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 100 MW to-be-constructed solar photovoltaic energy facility, Walnut Bend Solar facility, that will be sited on approximately 1,000 acres in Lee County, Arkansas. In July 2021 the APSC issued an order approving the acquisition of the Walnut Bend Solar facility. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination, and in February 2023 an amendment to the agreement was executed by the parties. In July 2023 the APSC issued an order approving the revisions to the agreement and full notice to proceed was issued shortly thereafter. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024;
•In September 2020, Entergy Arkansas signed an agreement for the purchase of an approximately 180 MW to-be-constructed solar photovoltaic energy facility, West Memphis Solar facility, that will be sited on approximately 1,500 acres in Crittenden County, Arkansas. In October 20172021 the APSC issued an order approving the acquisition of the West Memphis Solar facility. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC. Following the APSC’s approval of the supplemental application in March 2023, full notice to proceed was issued in April 2023 and the project is currently expected to achieve commercial operation by the end of 2024;
•In November 2021, Entergy Louisiana signed an agreement for the purchase of an approximately 150 MW to-be-constructed solar photovoltaic energy facility, St. Jacques facility, that will be sited in St. James Parish near Vacherie, Louisiana. In September 2022 the LPSC voted to issue an order approving the St. Jacques facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the continued recoverycounterparty for the St. Jacques facility regarding amendments to the agreement to address the impact of the nuclear dry fuel storage costs throughSt. James Parish ordinance, and the fuel adjustment clause, resolvingfacility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the open issueparties on the terms of the amendments;
•In August 2022, Entergy Arkansas signed an agreement for the purchase of an approximately 250 MW to-be-constructed solar photovoltaic energy facility, Driver Solar facility, that will be sited near Osceola, Arkansas. Also in August 2022, Entergy Arkansas received necessary approvals for the Driver Solar
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facility, and Entergy Arkansas has issued the counterparty full notice to proceed to begin construction. The project is expected to achieve commercial operation as early as mid-2024; and
•Entergy Louisiana expects to start construction on the 49 MW Sterlington Solar project in the audit.fourth quarter 2024, located in Sterlington, Louisiana. The facility is expected to achieve commercial operation in January 2026.
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 December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings ofSeptember 2012, Entergy Gulf States Louisiana and its affiliates.Rain CII Carbon LLC executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from a petroleum coke calcining facility in Sulphur, Louisiana. The audit included a review of the reasonableness of charges flowed byfacility 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 and Agrilectric Power Partners, LP executed a 20-year agreement for 8.5 MW from a 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 and TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, executed a 10-year agreement 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 its fuel adjustment clausethe RFP process). Cost recovery for the period 2005 through 2009. 90 MW was approved by the MPSC in January 2013;
•In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC approved the project and deliveries pursuant to that agreement commenced in June 2018;
•In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. In November 2019, LS Power sold and transferred the Carville Energy Center and facility to Argo Infrastructure Partners, which included the power purchase agreement;
•In November 2016, Entergy Louisiana and Occidental Chemical Corporation executed a 10-year agreement for 500 MW from the Taft Cogeneration facility located in Hahnville, Louisiana. The transaction received regulatory approval and began in June 2018;
•In June 2017, Entergy Arkansas and Chicot Solar, LLC executed a 20-year agreement for 100 MW from a to-be-constructed solar photovoltaic electric generating facility located in Chicot County, Arkansas. The transaction received regulatory approval and the PPA began in November 2020;
•In February 2018, Entergy Louisiana and LA3 West Baton Rouge, LLC (Capital Region Solar project) executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in West Baton Rouge Parish, Louisiana. The transaction received regulatory approval in February 2019 and the PPA began in October 2020;
•In July 2018, Entergy New Orleans and St. James Solar, LLC executed a 20-year agreement for 20 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. The transaction received regulatory approval in July 2019 and the PPA began in February 2023 after the facility reached commercial operation in March 2023;
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•In August 2018, Entergy Louisiana and South Alexander Development I, LLC executed a 5-year agreement for 5 MW from a solar photovoltaic electric generating facility located in Livingston Parish, Louisiana. The PPA began in December 2020 and received regulatory approval in January 2021;
•In February 2019, Entergy New Orleans and Iris Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. The transaction received regulatory approval in July 2019 and achieved commercial operation in November 2022;
•In August 2020, Entergy Texas and Umbriel Solar, LLC executed a 20-year agreement for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in Polk County, Texas. The facility achieved commercial operation in November 2023;
•In June 2021, Entergy Louisiana and Sunlight Road Solar, LLC executed a 20-year agreement for 50 MW from a to-be-constructed solar photovoltaic electric generating facility located in Washington Parish, Louisiana. In September 2022 the LPSC voted to approve the order including this project and in September 2023, Entergy Louisiana reported to the LPSC that it had entered into amended agreements related to the Sunlight Road facility. The facility is expected to reach commercial operation in December 2024;
•In June 2021, Entergy Louisiana and Vacherie Solar Energy Center, LLC executed a 20-year PPA for 150 MW from a to-be-constructed solar photovoltaic electric generating facility located in St. James Parish, Louisiana. In September 2022 the LPSC voted to issue an order approving the Vacherie facility; however, following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to establish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparty for the Vacherie facility regarding amendments to the agreement to address the impact of the St. James Parish ordinance, and the facility is expected to reach commercial operation no sooner than 2027 dependent upon agreement by the parties on the terms of the amendments;
•In December 2022, Entergy Mississippi and Hinds Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Hinds County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in June 2026;
•In October 2022, Entergy Mississippi and Wildwood Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Tallahatchie County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in May 2026;
•In October 2022, Entergy Mississippi and Greer Solar, LLC executed a 20-year PPA for approximately 170 MW from a to-be-constructed solar photovoltaic energy facility located in Washington County, Mississippi. In August 2023 the MPSC approved the PPA, and the facility is expected to reach commercial operation in December 2026;
•In October 2022, Entergy Arkansas and Flat Fork Solar, LLC executed a 20-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in St. Francis County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In October 2022, Entergy Arkansas and Forgeview Solar, LLC executed a 15-year PPA for approximately 200 MW from a to-be-constructed solar photovoltaic energy facility located in Mississippi County, Arkansas. In September 2023 the APSC approved the PPA, and the facility is expected to reach commercial operation in September 2025;
•In January 2023, Entergy Texas and Piney Woods Solar, LLC executed a 20-year PPA for approximately 150 MW from a to-be-constructed solar photovoltaic energy facility located in Walker County, Texas. The facility is expected to reach commercial operation as early as June 2026;
•In January 2023, Entergy Louisiana and Coastal Prairie Solar, LLC executed a 20-year PPA for approximately 175 MW from a to-be-constructed solar photovoltaic energy facility located in Iberville Parish, Louisiana. Following execution of the agreement, Entergy Louisiana filed a petition with the LPSC
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requesting all necessary approvals. The facility is expected to reach commercial operation as early as December 2025; and
•In October 2023, Entergy Louisiana and Mondu Solar, LLC executed a 20-year PPA for approximately 100 MW from a to-be-constructed solar photovoltaic energy facility located in Point Coupee Parish, 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 as early as June 2026.
In July 2021, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar generation resources. Entergy Texas selected a combination of PPA and owned resources in March 2022. One PPA was executed in January 2023 and the certificate of convenience and necessity for the owned resource is expected to be filed with the PUCT in mid-2024.
In April 2022, Entergy Services, on behalf of Entergy Arkansas, issued an RFP for solar photovoltaic and wind resources. Entergy Arkansas selected a combination of PPA and build own transfer resources in February 2023, and negotiation of definitive agreements for the resources are in progress.
In June 2022, Entergy Services, on behalf of Entergy Louisiana, issued an RFP for solar photovoltaic and wind resources. Entergy Louisiana selected a combination of PPA and build own transfer resources in March 2023 some of which have been executed and are noted above, and negotiation of definitive agreements for the remaining resources are in progress.
In October 2022, Entergy Services, on behalf of Entergy Texas, issued an RFP for solar photovoltaic and wind resources. Entergy Texas selected a combination of PPA and owned resources in July 2023, and negotiation of definitive agreements are in progress for all resources.
In November 2022, Entergy Services, on behalf of Entergy Mississippi, issued an RFP for solar photovoltaic and wind resources. Entergy Mississippi selected a combination of owned resources in May 2023, and negotiation of definitive agreements are in progress for all resources.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process and have also entered various limited- and long-term contracts in recent years as a result of bilateral negotiations, including among others:
•In March 2016, Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) 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). The facility is located near El Dorado, Arkansas and has been in operation since July 2003;
•In October 2019, Entergy Mississippi’s acquisition of the 810 MW, combined-cycle, natural gas-fired Choctaw Generating Station. The facility is located in Choctaw County and has been in operation since July 2003;
•In November 2020, Entergy Louisiana’s acquisition of 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. Calpine began construction on the plant in early 2019 and Entergy Louisiana purchased the plant upon completion in November 2020;
•In June 2021, Entergy Texas’s acquisition of 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. The facility has been in operation since January 2010; and
•In November 2021, Entergy Louisiana and Elizabeth Solar, LLC executed a 20-year PPA for approximately 125 MW from a to-be-constructed solar photovoltaic energy facility located in Allen Parish, Louisiana. In September 2022 the LPSC staff consultant issuedvoted to approve this project and in September 2023, Entergy Louisiana reported
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to the LPSC that it had entered into amended agreements related to the Elizabeth Solar facility. The facility is expected to reach commercial operation in August 2024.
Power Through Programs
In February 2019, Entergy Mississippi proposed a new technologies pilot to the MPSC, which was approved in December 2019. The pilot further modernized the energy grid and met customers’ evolving expectations by offering utility-owned, natural gas-fired backup generators to customers. Following conclusion of the three-year pilot, in October 2023, Entergy Mississippi proposed full-scale implementation of commercial scale, natural gas-fired resilient distributed generation, to be installed in front of the meter at commercial and industrial customer premises. The full-scale offering was approved by the MPSC in December 2023 along with an associated rate schedule, the Resiliency as a Service Rider Schedule. Entergy Mississippi can dispatch the units at times of peak demand, which can mitigate the typically higher energy and capacity costs borne by all customers during times of peak energy usage.
In December 2020, Entergy Texas filed an application with the PUCT to amend its audit report.certificate of convenience and necessity to own and operate up to 75 MW of natural gas-fired distributed generation to be installed at commercial and industrial customer premises. Under this proposal, Entergy Texas would own and operate a fleet of generators ranging from 100 kW to 10 MW that would supply a portion of Entergy Texas’s long-term resource needs and enhance the resiliency of Entergy Texas’s electric grid. This fleet of generators would also be available to customers during outages to supply backup electric service as part of a program known as “Power Through.” In its report,2021 session, the Texas legislature modified the Texas Utilities Code to exempt generators under 10 megawatts from the requirement to obtain a certificate of convenience and necessity. In addition, the PUCT announced an intent to conduct a broad rulemaking related to distributed generation and recommended that utilities with pending applications addressing distributed generation withdraw them. Accordingly, Entergy Texas withdrew its application for a certificate of convenience and necessity and associated tariff from the PUCT without prejudice to refiling. Entergy Texas continues to deploy certain customer-sited distributed generators under an existing PUCT-approved tariff. In August 2022, Entergy Texas filed an application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation through which it would charge host customers for back-up service from customer-sited Power Through generators. Based on the exemption enacted by the Texas legislature in 2021, Entergy Texas’s application was not required to, and did not, seek an amendment to its certificate of convenience and necessity in order to continue deploying Power Through generators. In October 2022 two intervenors filed requests for a hearing on Entergy Texas’s application. In October 2022 the PUCT staff filed a request that the proceeding be referred to the State Office of Administrative Hearings. In January 2023 the PUCT announced an intent to develop certain broadly applicable reliability metrics against which to measure distributed generation resources and directed Entergy Texas to withdraw its application. However, the PUCT did allow Entergy Texas to continue its pilot program for Power Through generators. Entergy Texas withdrew its application. In its 2023 session, the Texas legislature modified the Texas Utilities Code to confirm Entergy Texas’s ability to provide back-up generation service using customer-sited utility-owned distributed generation and directing the PUCT to approve rates for such service upon application by Entergy Texas. In February 2024, Entergy Texas resubmitted its application for PUCT approval of voluntary Rate Schedule Utility Owned Distributed Generation. A procedural schedule has not yet been set.
In August 2021, Entergy Arkansas filed with the APSC an application seeking authority for a “Power Through” offering to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Arkansas customers. In December 2021 the APSC general staff requested briefing, which Entergy Arkansas opposed. In January 2022, Entergy Arkansas filed to support the establishment of a procedural schedule with a hearing in April 2022. Also in January 2022, the APSC granted the general staff’s request for briefing but on an expedited schedule; briefing concluded in February 2022. Based on testimony filed to date the APSC general staff, Arkansas Electric Energy Consumers, Sierra Club, and Audubon opposed Entergy Arkansas’s proposed Power Through offering, which was demonstrated to be in high demand by interested customers, some of which directly filed public comments encouraging the APSC to approve the application. A
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paper hearing was held in August and September 2022, and Entergy Arkansas responded to several written commissioner questions. In May 2023 the APSC issued an order approving the Power Through offering with some modifications, and in June 2023, Entergy Arkansas sought rehearing or clarification of several issues. In August 2023 the APSC denied Entergy Arkansas’s rehearing petition. In December 2023 the APSC approved a streamlined approval process for the individual Power Through generators. Entergy Arkansas is developing tariff revisions to comply with the APSC’s order.
In July 2021, Entergy Louisiana filed with the LPSC staff consultant recommended thatan application for authority to deploy natural gas-fired distributed generation. The application was supported by a number of letters of interest from Entergy Louisiana refund approximately $8.6 million, plus interest,customers. In October 2021, a procedural schedule was established with a hearing in April 2022. Staff and certain intervenors filed direct testimony in December 2021, and cross-answering testimony was filed in January 2022. Entergy Louisiana filed rebuttal testimony in February 2022. The parties reached an uncontested settlement which, among other things, recommended approval of 120 MW of natural gas fired distributed generation and an additional 30 MW of solar and battery distributed generation, for a total distributed generation program of 150 MW. Pursuant to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that it was no longer recommending a disallowance of $3.4 millionterms of the $8.6 million discussed above, but otherwise maintained positions from its report. Subsequently,settlement agreement, Entergy Louisiana may seek to expand the parties entered into adistributed generation program following the earlier of two years after issuance of an order approving the settlement whichor the installation of 60 MW of distributed generation pursuant to this program. The settlement was approved by the LPSC in November 2016. 2022.
Interconnections
The settlement recognizedUtility operating companies’ generating units are interconnected to the dry casktransmission system which operates at various voltages up to 500 kV. These generating units consist of steam-turbine generators fueled by natural gas, coal, and pressurized and boiling water nuclear reactors; combustion-turbine generators, combined-cycle combustion turbine generators and reciprocating internal combustion engine generators that are fueled by natural gas; and inverter-based resources interconnecting both solar photovoltaic systems and energy storage recovery method issue, which was addresseddevices that participate in the separate proceedingMISO wholesale electric market. Additionally, some of the Utility operating companies also offer customer services and products that include generating and demand response resources that are interconnected to both the distribution and transmission systems and that also participate in the wholesale market. Entergy’s Utility operating companies are MISO market participants and the companies’ transmission systems are interconnected with those of many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. In addition, the Utility operating companies are members of SERC Reliability Corporation (SERC), the Regional Entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing Bulk Electric System reliability standards within 16 central and southeastern states.
Gas Property
As of December 31, 2023, 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, 2023, 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
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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 average fuel cost per kWh for the Utility operating companies and System Energy for the years 2021-2023 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year | | Natural Gas | | Nuclear | | Coal | | Renewables (a) | | Purchased Power | | MISO Purchases (b) |
| 2023 | | (Cents Per kWh) |
| Entergy Arkansas | | 1.98 | | | 0.50 | | | 3.09 | | | 1.98 | | | 11.57 | | | 0.77 | |
| Entergy Louisiana | | 2.34 | | | 0.60 | | | 3.22 | | | 10.38 | | | 3.76 | | | 2.50 | |
| Entergy Mississippi | | 2.21 | | | — | | | 2.82 | | | 0.03 | | | 5.86 | | | 1.84 | |
| Entergy New Orleans (c) | | 2.05 | | | — | | | — | | | 3.24 | | | — | | | 2.33 | |
| Entergy Texas | | 2.29 | | | — | | | 3.17 | | | 2.25 | | | 5.64 | | | 3.18 | |
| System Energy | | — | | | 0.68 | | | — | | | — | | | — | | | — | |
| Utility | | 2.25 | | | 0.58 | | | 3.06 | | | 6.14 | | | 4.03 | | | 2.61 | |
| | | | | | | | | | | | |
| 2022 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.98 | | | 0.52 | | | 2.93 | | | 2.11 | | | 10.90 | | | (2.65) | |
| Entergy Louisiana | | 5.50 | | | 0.57 | | | 2.84 | | | 10.70 | | | 6.95 | | | 6.45 | |
| Entergy Mississippi | | 4.38 | | | — | | | 2.85 | | | 0.04 | | | 6.53 | | | 6.68 | |
| Entergy New Orleans (c) | | 5.10 | | | — | | | — | | | (5.16) | | | — | | | 7.21 | |
| Entergy Texas | | 5.77 | | | — | | | 2.83 | | | 6.26 | | | 5.61 | | | 6.68 | |
| System Energy | | — | | | 0.65 | | | — | | | — | | | — | | | — | |
| Utility | | 5.27 | | | 0.57 | | | 2.89 | | | 7.00 | | | 6.54 | | | 5.95 | |
| | | | | | | | | | | | |
| 2021 | | | | | | | | | | | | |
| Entergy Arkansas | | 4.11 | | | 0.56 | | | 2.43 | | | 2.85 | | | 2.53 | | | 3.87 | |
| Entergy Louisiana | | 3.77 | | | 0.56 | | | 2.62 | | | 10.87 | | | 5.52 | | | 4.04 | |
| Entergy Mississippi | | 2.71 | | | — | | | 2.53 | | | 1.22 | | | 2.70 | | | 4.16 | |
| Entergy New Orleans (c) | | 3.47 | | | — | | | — | | | (2.82) | | | — | | | 4.50 | |
| Entergy Texas | | 4.65 | | | — | | | 2.60 | | | 3.97 | | | 4.53 | | | 4.10 | |
| System Energy | | — | | | 0.55 | | | — | | | — | | | — | | | — | |
| Utility | | 3.75 | | | 0.56 | | | 2.48 | | | 9.07 | | | 4.76 | | | 4.08 | |
(a)Includes average fuel costs from both owned and purchased power resources.
(b)Includes activity from financial transmission rights. See Note 15 to the financial statements for discussion of financial transmission rights.
(c)Entergy New Orleans’s renewables include liquidated damage payments of $0.1 million in 2023, $2.9 million in 2022, and $1 million in 2021 due to the delay of in-service dates related to purchased power agreements.
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Actual 2023 and projected 2024 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
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| 2023 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | 1 | % | | 57 | % | | 9 | % | | 3 | % | | — | % | | 4 | % |
| Entergy Louisiana | 47 | % | | 7 | % | | 20 | % | | 2 | % | | 2 | % | | 10 | % | | 12 | % |
| Entergy Mississippi | 63 | % | | 1 | % | | 23 | % | | 7 | % | | 1 | % | | — | % | | 5 | % |
| Entergy New Orleans | 55 | % | | 1 | % | | 36 | % | | 1 | % | | 2 | % | | 1 | % | | 4 | % |
| Entergy Texas | 32 | % | | 25 | % | | 6 | % | | 3 | % | | — | % | | 4 | % | | 30 | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 43 | % | | 7 | % | | 27 | % | | 4 | % | | 2 | % | | 5 | % | | 12 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 |
| | CT / CCGT (b) | | Legacy Gas | | Nuclear | | Coal | | Renewables (c) | | Purchased Power (d) | | MISO Purchases (e) |
| Entergy Arkansas | 26 | % | | — | % | | 59 | % | | 12 | % | | 3 | % | | — | % | | — | % |
| Entergy Louisiana | 48 | % | | 6 | % | | 30 | % | | 2 | % | | 3 | % | | 11 | % | | — | % |
| Entergy Mississippi | 64 | % | | — | % | | 24 | % | | 10 | % | | 2 | % | | — | % | | — | % |
| Entergy New Orleans | 51 | % | | 1 | % | | 43 | % | | 1 | % | | 3 | % | | 1 | % | | — | % |
| Entergy Texas | 43 | % | | 31 | % | | 17 | % | | 6 | % | | 3 | % | | — | % | | — | % |
| System Energy (a) | — | % | | — | % | | 100 | % | | — | % | | — | % | | — | % | | — | % |
| Utility | 45 | % | | 6 | % | | 35 | % | | 6 | % | | 3 | % | | 5 | % | | — | % |
(a)Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
(b)Represents natural gas sourced for Simple Cycle Combustion Turbine units and Combined Cycle Gas Turbine units.
(c)Includes generation from both owned and purchased power resources.
(d)Excludes MISO purchases and renewables purchased through purchased power agreements.
(e)In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers, with MISO making dispatch decisions. The MISO purchases metric provided for 2023 is not projected for 2024.
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 2024, 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 70% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements.
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Entergy Texas owns a gas storage facility and Entergy Louisiana has a firm storage service agreement that provide reliable and flexible natural gas service to certain generating stations.
Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is primarily tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies may in some instances use alternate fuels, such as oil when available, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has committed to six two- to three-year contracts that will supply at least 85% of the total coal supply needs in 2024. These contracts are staggered in term so that not all contracts have to be renewed the same year. If needed, additional Powder River Basin (PRB) coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. Based on the high cost of alternate sources, modes of transportation, and infrastructure improvements necessary for its delivery, no alternative coal consumption is expected at Entergy Arkansas during 2024. Coal will be transported to Arkansas via an existing Union Pacific transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2024.
Entergy Louisiana has committed to three two- to three-year contracts that will supply at least 90% of Nelson Unit 6 coal needs in 2024. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as the Entergy Arkansas plants, no alternative coal consumption is expected at Nelson Unit 6 during 2024. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Louisiana’s rail transportation requirements for 2024.
Coal transportation delivery rates to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units were able to fully meet supply needs and obligations in 2023. While deliveries remained constrained through summer 2023, improvements were observed in the second half of the year and are expected to continue in 2024. Both Entergy Arkansas and Entergy Louisiana control enough railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2024, but is also currently experiencing delivery constraints. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
Nuclear Fuel
The nuclear fuel cycle consists of the following:
•mining and milling of uranium ore to produce a concentrate;
•conversion of the concentrate to uranium hexafluoride gas;
•enrichment of the uranium hexafluoride gas;
•fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and
•disposal of spent fuel.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated
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uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the Utility nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through 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 ensures 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 2023 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.
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As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
Transmission and MISO Markets
In December 2013 the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO did not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their owned and controlled generating facilities into the MISO resource adequacy construct (the annual Planning Resource Auction), as well as the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The resource adequacy construct provided under the MISO tariff confers certain rights and imposes certain obligations upon load-serving entities, including the Utility operating companies, that are served from the transmission systems subject to MISO’s functional control, including the transmission facilities of the Utility operating companies. The MISO tariff is subject to change and has recently undergone significant changes. As an example, MISO recently has made changes to its capacity accreditation methodology for thermal resources which emphasize performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now pursuing a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources.
MISO administers a process governed by the MISO tariff and subject to the FERC regulation that governs the interconnection of new generation resources to the transmission system under MISO’s functional control. This process generally involves parties that wish to interconnect new generation resources submitting to MISO requests to do so, which are then studied and analyzed by MISO, with the participation of its member transmission owners, to determine if the interconnection of such generators requires new transmission facilities to ensure the continued reliable operations of the grid. Under MISO’s current tariff, these requests are studied and considered in clusters, generally in the order in which they are received – a system of priority known as the MISO interconnection queue.
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.
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
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membership as well as the projected costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of proceedings at the FERC related to System Energy.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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 retail 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. 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 October 2017, providedrates. 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. The remainder of Entergy Arkansas’s retained share is sold to Entergy Mississippi through a refundseparate life-of-resource purchase power agreement with Entergy Mississippi. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of $5 million,the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted cost recovery for those purchases by the MPSC through its annual unit power cost rate mechanism.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the original financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy
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Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of operating expense funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for all of its outstanding series of first mortgage bonds, as well as for its outstanding term loan and the pollution control revenue refunding bonds issued on its behalf. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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 to System Energy have ever been required. However, if Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or certain of its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their allocated shares under the Availability Agreement exceed their allocated shares under the Unit Power Sales Agreement. See Note 8 to the financial statements for discussion of the Reallocation Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, pursuant to which was madeEntergy Louisiana, Entergy Mississippi, and Entergy New Orleans
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assumed all of Entergy Arkansas’s responsibilities and obligations with respect to legacyGrand Gulf under the Availability Agreement.
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, as well as to Entergy’s non-utility operations business. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations, and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana customers inand Entergy Texas
Effective December 2016,31, 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 resolved allthe other issues raised inoperating under the audit.
In July 2014sole retail jurisdiction of the LPSC, authorized its staff to initiate an auditEntergy 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, Louisiana’s fuel adjustment clause filings. The audit includes a reviewInc.’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 reasonableness of charges flowedremaining 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
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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 Arkansas Internal Restructuring
In November 2018, Entergy Arkansas undertook a multi-step restructuring, including the following:
•Entergy Arkansas, Inc. redeemed its outstanding preferred stock at the aggregate redemption price of approximately $32.7 million.
•Entergy Arkansas, Inc. converted from an Arkansas corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Arkansas, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Arkansas Power, LLC, a Texas limited liability company (Entergy Arkansas Power), and Entergy Arkansas Power assumed substantially all of the liabilities of Entergy Arkansas, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Arkansas, Inc. remained in existence and held the membership interests in Entergy Arkansas Power.
•Entergy Arkansas, Inc. contributed the membership interests in Entergy Arkansas Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Arkansas Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Arkansas, Inc. changed its name to Entergy Utility Property, Inc., and Entergy Arkansas Power then changed its name to Entergy Arkansas, LLC. Entergy Arkansas, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Arkansas, Inc. The transaction was accounted for as a transaction between entities under common control.
Entergy Mississippi Internal Restructuring
In November 2018, Entergy Mississippi undertook a multi-step restructuring, including the following:
•Entergy Mississippi, Inc. redeemed its outstanding preferred stock, at the aggregate redemption price of approximately $21.2 million.
•Entergy Mississippi, Inc. converted from a Mississippi corporation to a Texas corporation.
•Under the Texas Business Organizations Code (TXBOC), Entergy Mississippi, Inc. allocated substantially all of its assets to a new subsidiary, Entergy Mississippi Power and Light, LLC, a Texas limited liability company (Entergy Mississippi Power and Light), and Entergy Mississippi Power and Light assumed substantially all of the liabilities of Entergy Mississippi, Inc., in a transaction regarded as a merger under the TXBOC. Entergy Mississippi, Inc. remained in existence and held the membership interests in Entergy Mississippi Power and Light.
•Entergy Mississippi, Inc. contributed the membership interests in Entergy Mississippi Power and Light to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy Mississippi Power and Light is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2018, Entergy Mississippi, Inc. changed its name to Entergy Utility Enterprises, Inc., and Entergy Mississippi Power and Light then changed its name to Entergy Mississippi, LLC. Entergy Mississippi, LLC holds substantially all of the assets, and assumed substantially all of the liabilities, of Entergy Mississippi, Inc. The restructuring was accounted for as a transaction between entities under common control.
Other Business Activities
Entergy’s non-utility operations business includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. Entergy’s non-utility operations
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business also provides decommissioning-related services to nuclear power plants owned by non-affiliated entities in the United States.
Property
Entergy’s non-utility operations business owns interests in the following non-nuclear power plants:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant | | Location | | Ownership | | Net Owned Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
| Nelson Unit 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
(a)“Net Owned Capacity” refers to the nameplate rating on the generating unit.
(b)The owned MW capacity is the portion of the plant capacity owned by Entergy’s non-utility operations business. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.
All generation owned by Entergy’s non-utility operations business falls under the authority of MISO. Customers for the sale of both energy and capacity from its owned generation and contracted power purchases include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. The majority of the non-utility operations businesses’ owned generation and contracted power purchases are sold under a cost-based contract.
TLG Services, a subsidiary in Entergy’s non-utility operations business, offers decommissioning, engineering, and related services to nuclear power plant owners.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
•the transmission and wholesale sale of electric energy in interstate commerce;
•the reliability of the high voltage interstate transmission system through reliability standards;
•sale or acquisition of certain assets;
•securities issuances;
•the licensing of certain hydroelectric projects;
•certain other activities, including accounting policies and practices of electric and gas utilities; and
•changes in control of FERC jurisdictional entities or rate schedules.
The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over the rates charged by Entergy Arkansas and Entergy Louisiana to unaffiliated wholesale customers. The FERC also regulates wholesale power sales between the Utility operating companies. In addition, the FERC regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as 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.
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Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 65 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery rider;
•terms and conditions of service;
•service standards;
•the acquisition, sale, or lease of any public utility plant or property constituting an operating unit or system;
•certificates of convenience and necessity and certificates of environmental compatibility and public need, as applicable, for generating and transmission facilities;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering;
•integrated resource planning;
•utility mergers and acquisitions and other changes of control; and
•the issuance and sale of certain securities.
Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee. Pursuant to legislation enacted in Tennessee, Entergy Arkansas is subject to complaints before the Tennessee Regulatory Authority only if it fails to treat its retail customers in Tennessee in the same manner as its retail customers in Arkansas. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to retail ratemaking jurisdiction in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment clause, for the period from 2010 through 2013. Discovery commenced in July 2015. No report of audit has been issued.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuelenvironmental 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. Discovery commenced in July 2015. No report of audit has been issued.
In June 2016 the LPSC staff provided notice of audits of Entergy Louisiana’s fuel adjustment clause filingscharge, and purchased gas adjustment clause filings.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 at or above 50 MW;
•audits of the energy efficiency rider;
•avoided cost payment to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers and acquisitions and other changes of control.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
•utility service;
•utility service areas;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the energy cost recovery mechanism;
•terms and conditions of service;
•service standards;
•certification of generating facilities, certain transmission projects, and certain distribution projects with construction costs greater than $10 million;
•avoided cost payments to non-exempt Qualifying Facilities;
•integrated resource planning;
•net energy metering; and
•utility mergers, acquisitions, and other changes of control.
Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
•utility service;
•retail rates and charges, including depreciation rates;
•fuel cost recovery, including audits of the fuel adjustment charge and purchased gas adjustment charge;
•terms and conditions of service;
•service standards;
•audit of the environmental adjustment charge;
•certification of the construction or extension of any new plant, equipment, property, or facility that comprises more than 2% of the utility’s rate base;
•integrated resource planning;
•net energy metering;
•avoided cost payments to non-exempt Qualifying Facilities;
•issuance and sale of certain securities; and
•utility mergers and acquisitions and other changes of control.
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to the following:
•retail rates and charges, including depreciation rates, and terms and conditions of service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;
•fuel recovery, including reconciliations (audits) of the fuel adjustment charges;
•service standards;
•certification of certain transmission and generation projects;
•utility service areas, including extensions into new areas;
•avoided cost payments to non-exempt Qualifying Facilities;
•net energy metering; and
•utility mergers, sales/acquisitions/leases of plants over $10 million, sales of greater than 50% voting stock of utilities, and transfers of controlling interest in or operation of utilities.
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Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose civil penalties or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC.
Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2023 of $205.2 million for the one-time fee. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.7 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing of the Yucca Mountain repository (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 is in partial breach of 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
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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 2021, 2022, and 2023 related to Entergy’s nuclear owner/licensee subsidiaries’ litigation with the DOE. Through 2023, Entergy’s subsidiaries have won and collected on judgments against the government totaling approximately $1 billion.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at ANO in 1996, at River Bend in 2005, at Grand Gulf in 2006, and at Waterford 3 in 2011. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used in accordance with NRC and other applicable regulatory requirements. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In December 2018 the APSC ordered collections in rates for decommissioning ANO 2 and found that ANO 1’s decommissioning was adequately funded without additional collections. In November 2021, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that both ANO 1 and 2 decommissioning trusts were adequately funded without further collections, and in December 2021 the APSC ordered zero collections for ANO 1 and 2 decommissioning. In November 2022, Entergy Arkansas filed a revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust was adequately funded, but that ANO 2’s fund had a projected shortage as a result of a decline in decommissioning trust fund investment values over the past year. The filing proposed a reinstatement of decommissioning cost recovery for ANO 2. In December 2022 the APSC ordered reinstatement of decommissioning collections for ANO 2 in accordance with the request in the November 2022 filing. In November 2023, Entergy Arkansas filed a further revised decommissioning cost recovery tariff for ANO indicating that ANO 1’s decommissioning trust continued to be adequately funded, but that ANO 2’s fund continued to require collections higher than those in effect. In December 2023 the APSC approved the proposed higher decommissioning collections for ANO 2.
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
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3 and River Bend decommissioning collections based on the latest site-specific decommissioning cost estimates for those plants. The filing seeks to increase Waterford 3 decommissioning collections and decrease River Bend decommissioning collections. The procedural schedule in the case has been suspended pending settlement negotiations. In August 2023, Entergy Louisiana made another filing with the LPSC requesting to maintain the same total decommissioning funding collections as currently in effect for both Waterford 3 and River Bend combined, but also requesting to reallocate that same amount of funding by increasing the contributions for Waterford 3 and reducing the contributions for River Bend. In October 2023 a procedural schedule was adopted that includes a hearing date in August 2024. Management cannot predict the outcome of these proceedings.
In December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2018 the PUCT approved a settlement that eliminated River Bend decommissioning collections for the Texas jurisdictional share of the plant based on a determination by Entergy Texas that the existing decommissioning fund was adequate following license renewal. In July 2022, Entergy Texas filed a base rate case that proposed continuation of the cessation of River Bend decommissioning collections. In May 2023, Entergy Texas filed on behalf of the parties to the base rate case an unopposed settlement, which included an agreement to maintain Entergy Texas’s decommissioning funding for River Bend at a revenue requirement of $0. In August 2023 the PUCT issued an order accepting the unopposed settlement, including the proposed decommissioning funding settlement terms.
In December 2016 the NRC issued a 20-year operating license renewal for Grand Gulf. In a 2017 filing at the FERC, System Energy stated that with the renewed operating license, Grand Gulf’s decommissioning trust was sufficiently funded, and proposed, among other things, to cease decommissioning collections for Grand Gulf effective October 1, 2017. The FERC accepted a settlement including the proposed decommissioning revenue requirement by letter order in August 2018.
Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
Plant owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. In March 2023 filings with the NRC were made reporting on decommissioning funding for all of Entergy’s subsidiaries’ nuclear plants. Those reports showed that decommissioning funding for each of the nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $165.9 million per reactor (with 95 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, or System Energy is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to
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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, “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 with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. All of the nuclear generating plants owned and operated by Entergy’s Utility business are currently in Column 1, except River Bend, which is in Column 2.
In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.
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;
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•Interstate Air Transport;
•operating permit programs and enforcement of these and other Clean Air Act programs;
•Regional Haze programs; and
•new and existing source standards for greenhouse gas and other air emissions.
National Ambient Air Quality Standards
The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for ozone, carbon monoxide, lead, nitrogen dioxide, particulate matter, and sulfur dioxide and requires periodic review of those standards. When an area fails to meet an ambient standard, it is considered to be in nonattainment and is classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
Ozone Nonattainment
Entergy Texas operates two fossil-fueled generating facilities (Lewis Creek and Montgomery County Power Station) in a geographic area that is not in attainment with the applicable NAAQS for ozone. The ozone nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Both Lewis Creek and the Montgomery County Power Station hold all necessary permits for operation and comply with applicable air quality program regulations. Measures enacted to return the area to ozone attainment could make these program regulations more stringent. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and nonattainment with the ozone NAAQS.
Potential SO2Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. In Entergy’s utility service territory, only St. Bernard Parish and Evangeline Parish in Louisiana are designated as nonattainment. In August 2017 the EPA issued a letter indicating that East Baton Rouge and St. Charles parishes would be designated by December 31, 2020, as monitors were installed to determine compliance. In March 2021 the EPA published a final rule designating East Baton Rouge, St. Charles, St. James, and West Baton Rouge parishes in Louisiana as attainment/unclassifiable and, in Texas, Jefferson County as attainment/unclassifiable and Orange County as unclassifiable. No challenges to these final designations were filed within the 60 day deadline. Entergy continues to monitor this situation.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units. In May 2020 the EPA finalized a rule that finds that it is not “appropriate and necessary” to regulate hazardous air pollutants from electric steam generating units under the provisions of section 112(n) of the Clean Air Act. This is a reversal of the EPA’s previous finding requiring such regulation. The final appropriate and necessary finding does not revise the underlying MATS rule. Several lawsuits have been filed challenging the appropriate and necessary finding. In February 2021 the D.C. Circuit granted the EPA’s motion to hold the litigation in abeyance pending the agency’s review of the appropriate and necessary rule. In February 2022 the EPA issued a proposed rule revoking the 2020 rule and determining, again, that it is “appropriate and necessary” to regulate hazardous air pollutants. In April 2023 the EPA issued a regulatory proposal to revise portions of the MATS rule, including a proposed reduction to the emission limit for filterable particulate matter. If finalized, the proposed lower filterable particulate matter emission limitation could require additional capital investment and/or additional other operation and maintenance costs at Entergy’s coal-fired generating units. Entergy is closely monitoring this rulemaking, in part through its various trade associations.
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Good Neighbor Plan/Cross-State Air Pollution Rule
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy. Based on several court challenges, CAIR and its subsequent versions, now known as the Cross-State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions.
In June 2023 the EPA published its final Federal Implementation Plan (FIP), known as the Good Neighbor Plan, to address interstate transport for the 2015 ozone NAAQS which would increase the stringency of the CSAPR program in all four of the states where the Utility operating companies operate. The FIP would significantly reduce ozone season NOx emission allowance budgets and allocations for electric generating units. Entergy is currently assessing its compliance options for the FIP. Prior to issuance of the FIP, in February 2023 the EPA issued related State Implementation Plan (SIP) disapprovals for many states, including the four states in which the Utility operating companies operate, and these SIP disapprovals are the subject of many legal challenges, including a petition for review filed by Entergy Louisiana challenging the disapproval of Louisiana’s SIP. Stays of the SIP disapprovals have been granted in all four states in which the Utility operating companies operate, and the Good Neighbor Plan will not go into effect while the stays are in place. Decisions on the merits regarding the respective SIP disapprovals are expected in 2024. The final FIP also is subject to numerous legal challenges.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states. This rule establishes a series of 10-year planning periods, with states required to develop 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.
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 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, NISCO, and Ninemile. Responses to the information collection requests were submitted to the respective state agencies. Louisiana issued its draft SIP which did not propose any additional air emissions controls for the affected Entergy units in Louisiana. Some public commenters, however, believe additional air controls are cost-effective. It is not yet clear how the Louisiana Department of Environmental Quality (LDEQ) will respond in its final SIP, and the agency, like many other state agencies, did not meet the July 31, 2021 deadline to submit a SIP to the EPA for review.
Similar to the LDEQ, the Arkansas Department of Energy and Environment, Division of Environmental Quality (ADEQ) did not meet the July 31, 2021 SIP submission deadline, but subsequently submitted it to the EPA for review. The ADEQ reviewed Entergy’s Independence plant but determined that additional air emission controls would not be cost-effective considering the facility’s commitment to cease coal-fired combustion by December 31, 2030.
The Texas Commission on Environmental Quality has completed its second-planning period SIP and submitted it to the EPA for review. There were no Entergy sources selected for additional emission controls. The
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Mississippi Department of Environmental Quality also did not meet the July 31, 2021 SIP submission deadline and continues to develop its SIP, but there are no Entergy sources that are expected to be impacted.
In August 2022 the EPA issued findings of failure to submit regional haze SIPs to 15 states, including Louisiana and Mississippi. These findings were effective September 2022 and start the two-year period for the EPA to either approve a SIP submitted by the state or issue a final federal plan.
Greenhouse Gas Emissions
In 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.
Consistent with the Biden administration’s stated climate goals, in May 2023 the EPA proposed several rules regulating greenhouse gas emissions from new and existing coal and gas-fired power plants. If finalized, the proposed requirements for existing “large and frequently used” gas turbine generating units could require significant investments in CO2 emission reduction technologies at certain of Entergy’s existing gas turbine units with a capacity of greater than 300 MW per combustion turbine and which operate at an annual capacity factor of greater than 50 percent. Comments on the proposed rules were submitted in August 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Entergy continues to support national legislation that would most efficiently reduce economy-wide greenhouse gas emissions and increase planning certainty for electric utilities. By virtue of its proportionally large investment in low-emitting generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per megawatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included a formal program to stabilize owned power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. In 2006, Entergy started including emissions from controllable power purchases in addition to its ownership share of generation and established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases, cumulatively over the period, at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020, which it ultimately outperformed by approximately 8% both cumulatively and on an annual basis. In 2019, in connection with a climate scenario analysis following the recommendations of the Task Force on Climate-related Financial Disclosures describing climate-related governance, strategy, risk management, and metrics and targets, Entergy announced a 2030 carbon dioxide emission rate goal focused on a 50% reduction from Entergy’s base year - 2000. In September 2020, Entergy announced a commitment to achieve net-zero greenhouse gas emissions by 2050 inclusive of all businesses, all applicable gases, and all emission scopes. In 2022, Entergy enhanced its commitment to include an interim goal of 50% carbon-free energy generating capacity by 2030 and expanded its interim emission rate goal to include all purchased power. See “Risk Factors” in Part I, Item 1A for discussion of the risks associated with achieving these climate goals. Entergy’s comprehensive, third party verified greenhouse gas inventory and progress against its voluntary goals are published on its website.
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Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
•reconsideration and revision of ambient air quality standards downward which could lead to additional areas of nonattainment;
•designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;
•introduction of bills in Congress and development of regulations by the EPA proposing further limits on SO2, mercury, carbon dioxide, and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;
•efforts in Congress or at the EPA to establish a federal carbon dioxide emission tax, control structure, or unit performance standards;
•revisions to the estimates of the Social Cost of Carbon and its use for regulatory impact analysis of federal laws and regulations;
•implementation of the regional cap and trade programs to limit carbon dioxide and other greenhouse gases;
•efforts on the local, state, and federal level to codify renewable portfolio standards, clean energy standards, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;
•efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;
•efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of polychlorinated biphenyls (PCBs) and increased regulation of per- and polyfluorinated substances or other chemicals;
•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 of the Clean Water Act regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
Federal Jurisdiction of Waters of the United States
In June 2020 the EPA’s revised definition of waters of the United States in the Navigable Waters Protection Rule (NWPR) became effective, narrowing the scope of Clean Water Act jurisdiction, as compared to a 2015
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definition which had been stayed by several federal courts. In August 2021 a federal district court vacated and remanded the NWPR for further consideration. The EPA and the U.S. Army Corps of Engineers (Corps) subsequently issued a statement that the agencies would revert to pre-2015 regulations pending a new rulemaking. In December 2022 the EPA and the Corps released a final definition of waters of the United States (the 2022 Rule) that replaces the NWPR with a definition that is consistent with the pre-2015 regulatory regime as interpreted by several United States Supreme Court decisions. The 2022 Rule was subject to multiple legal challenges and was enjoined from implementation or enforcement throughout Entergy’s utility service territory. In May 2023 the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands, and in September 2023 the EPA and the Corps issued a final rule incorporating the Supreme Court decision. Most notably, the exclusion for waste treatment systems is retained.
Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint, and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities including nuclear facilities that have been 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 April 2015 the EPA published the final coal combustion residuals (CCR) rule regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes regulated under Resource Conservation and Recovery Act Subtitle D. The final regulations created new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria but excluded CCRs that are beneficially reused in certain processes. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed. As of December 31, 2023, Entergy has recorded asset retirement obligations related to CCR management of $28 million.
Pursuant to the EPA Rule, Entergy operates groundwater monitoring systems surrounding its coal combustion residual landfills located at White Bluff, Independence, and Nelson. Monitoring to date has detected concentrations of certain listed constituents in the area, but has not indicated that these constituents originated at the active landfill cells. Reporting has occurred as required, and detection monitoring will continue as the rule requires. In late-2017, Entergy determined that certain in-ground wastewater treatment system recycle ponds at its White Bluff and Independence facilities require management under the new EPA regulations. Consequently, in order to move away from using the recycle ponds, White Bluff and Independence each 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 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.
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Additionally, all three sites are preparing to implement measures to meet the new and updated Effluent Limitation Guidelines (ELG). The nature, cost, and timing of those compliance measures depends on the guidance included in the final ELG rule, which is expected by mid-2024.
In May 2023 the EPA released a proposed rule establishing management standards for legacy CCR surface impoundments (i.e., inactive surface impoundments at inactive power plants) and establishing a new class of units referred to as CCR management units (i.e., non-containerized CCR located at a regulated CCR facility). Entergy does not have any legacy impoundments; however, the proposed definition of CCR management units appears to regulate on-site areas where CCR was beneficially used. This is contrary to the current CCR rule which exempts beneficial uses that meet certain criteria. Comments on the proposed rule were submitted in July 2023 and Entergy is monitoring the rulemaking, in part through its trade associations.
Other Environmental Matters
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas
The EPA notified Entergy that the EPA believes Entergy is a PRP concerning PCB contamination at the F.J. Doyle Salvage facility in Leonard, Texas. The facility operated as a scrap salvage business during the 1970s to the 1990s. In May 2018 the EPA investigated the site surface and sub-surface soils, and in November 2018 the EPA conducted a removal action, including disposal of PCB contaminated soils. Entergy responded to the EPA’s information requests in May and July 2019. In November 2020 the EPA sent Entergy and other PRPs a demand letter seeking reimbursement for response costs totaling $4 million expended at the site. Liability and PRP 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 and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the states in which Entergy and the Registrant Subsidiaries operate have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Asbestos Litigation(Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
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Human Capital
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2023, Entergy subsidiaries employed 12,177 people.
| | | | | |
| Utility: | |
| Entergy Arkansas | 1,302 | |
| Entergy Louisiana | 1,639 | |
| Entergy Mississippi | 747 | |
| Entergy New Orleans | 302 | |
| Entergy Texas | 704 | |
| System Energy | — | |
| Entergy Operations | 3,349 | |
| Entergy Services | 4,117 | |
| Entergy Nuclear Operations | 14 | |
| Other subsidiaries | 3 | |
| Total Entergy | 12,177 | |
There are 3,104 employees represented by the International Brotherhood of Electrical Workers, the United Government Security Officers of America, and the International Union, Security, Police, and Fire Professionals of America.
Below is the breakdown of Entergy’s employees by gender and race/ethnicity:
| | | | | | | | | | | |
| Gender (%) (a) | 2023 | | 2022 |
| Female | 23.0 | | 22.2 |
| Male | 77.0 | | 77.8 |
| | | | | | | | | | | |
| Race/Ethnicity (%) (a) | 2023 | | 2022 |
| White | 73.1 | | 74.8 |
| Black/African American | 18.2 | | 17.3 |
| Hispanic/Latino | 3.2 | | 3.0 |
| Asian | 3.2 | | 2.3 |
| Other | 2.3 | | 2.6 |
(a)Based on employees who self-identify.
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.
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Entergy Corporation, Utility operating companies, and System Energy
Governance and Oversight
Ensuring that workplace processes support the desired culture and strategy begins with the Board of Directors and the Office of the Chief Executive. The Talent and Compensation Committee establishes priorities and each quarter reviews strategies and results on a range of topics covering diversity, culture, and commerce. It oversees Entergy’s incentive plan design and administers its executive compensation plans to incentivize the behaviors and outcomes that support achievement of Entergy’s corporate objectives. Annually, it reviews executive performance, development, succession plans, and talent pipeline to align a high performing executive team with Entergy’s priorities. The Talent and Compensation Committee also oversees Entergy’s performance through regular briefings on a wide variety of human resources topics including Entergy’s safety culture and performance; organizational health; and diversity, inclusion, and belonging initiatives and performance.
The Talent and Compensation Committee is responsible 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 diversity, culture, and commerce measures, including 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. Entergy employees achieved a total recordable incident rate of 0.49 in 2023 as compared to 0.51 in 2022 and 0.46 in 2021. The results of 2021 unfortunately included an employee fatality. Entergy has enhanced dramatically leadership efforts and field presence to further its objective of zero fatalities, which it achieved in 2022 and 2023, although in early 2024 Entergy experienced a contractor fatality. Also in 2023, there was a significant decrease in the number of serious injuries. The recordable incident rate equals the number of recordable incidents per 100 full-time equivalents. Recordable incidents include fatalities, lost-time accidents, restricted-duty accidents, and medical attentions.
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 2021 of 63 (third quartile), in 2022 of 61 (third quartile), and in 2023 of 62 (third quartile). Although the score is nearly the same in 2023 as in 2022, Entergy has maintained improvement from the 2014 baseline. Improvement in behavioral expectations, which are the leading indicators of outcome improvements, indicates that Entergy is moving in a positive direction.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy believes that creating a culture of diversity, inclusion, and belonging drives foundational engagement for all employees. Entergy is committed to developing and retaining a top-performing workforce that reflects the rich diversity of the communities it serves. In 2021, Entergy established a new Diversity and Workforce Strategies organization to serve as a center of excellence for workforce development, talent attraction/pipeline development, and organizational health and diversity. The organization supports Entergy’s actions to strengthen our partnerships with colleges and vocational-technical schools for a more viable pipeline of future talent while expanding efforts to increase employee engagement and cultivate an inclusive culture with high performance. Entergy continues to focus its actions to engage a diverse workforce, infusing DIB into hiring policies, practices, and procedures, aligning Employee Resource Group goals to business objectives, growing its DIB Champion network, ensuring that Entergy’s leadership development programs support all employees, 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 highly qualified, 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, proxy statements, and amendments to such filings. The SEC maintains an internet site that occurredcontains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at https://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, https://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations, and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q and current reports on Form 8-K (including related filings in 2015,XBRL format); proxy statements; and any amendments to such filings. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the audit notice was issuedaddress to its internet site solely for the information of investors and does not intend the address to be an active link. Notwithstanding this reference or any references to the website in this report, the contents of the website are not incorporated into this report.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Item 1A. Risk Factors
See “RISK FACTORS SUMMARY” in Part I, Item 1 for a summary of Entergy’s and the Registrant Subsidiaries’ risk factors.
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s business, 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 willSystem Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal, potentially resulting in delays in effecting rate changes, lengthy litigation, the risk of disallowance of recovery of certain costs, and uncertainty as to ultimate results.
The Utility operating companies are regulated on a cost-of-service and rate of return basis and are subject to statutes and regulatory commission rules and procedures. The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment, including adjustment upon the initiative of a regulator or, in some cases, affected stakeholders. Regulators in a future rate proceeding may alter the timing or amount of certain costs for which recovery is allowed or modify the current authorized rate of return. Rate refunds may also include a reviewbe required, subject to applicable law.
In addition, regulators have initiated and may initiate additional proceedings to investigate the prudence of chargescosts 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 legacy Entergy Gulf States Louisiana customers priorplace 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 business combination.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 audit includeslength of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates, such that the Utility operating companies may not fully recover all costs during the rate effective period and may, therefore, earn less than their allowed returns. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. For a reviewdiscussion of such appeals and related litigation for both the Utility operating companies and System Energy, see Note 2 to the financial statements.
The Utility operating companies have large customer and stakeholder bases and, as a result, could be the subject of public criticism or adverse publicity focused on issues including, but not limited to, the operation and maintenance of their assets and infrastructure, including with respect to climate or environmental matters, their preparedness for major storms or other extreme weather events and/or the time it takes to restore service after such
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Entergy Corporation, Utility operating companies, and System Energy
events, the quality of their customer service, including timely and accurate billing practices and ability to resolve customer complaints, and the reasonableness of charges flowedthe cost 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 potentially negatively affect legislative or regulatory processes or outcomes, as well as lead to increased regulatory oversight or more stringent legislative or regulatory requirements or other legislation or regulatory actions that adversely affect the Utility operating companies.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect Entergy, the Utility operating companies, and System Energy’s business, financial position, results of operation, or cash flows. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.
Changes to state or federal legislation or regulation affecting electric generation, electric and natural gas transmission, distribution, and related activities could adversely affect Entergy and the Utility operating companies’ financial position, results of operations, or cash flows and their utility businesses.
If legislative and regulatory structures evolve in a manner that erodes the Utility operating companies’ exclusive rights to serve their regulated customers, such as through Entergy Louisiana’s fuel adjustment clause for“retail open access” or otherwise, 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 period from 2014 through 2015costs of these technologies and, charges flowed through Entergy Louisiana’s purchased gas adjustment clause fortogether with ongoing state and federal subsidies, the period from 2012 through 2015. Discovery commencedincreasing penetration of these technologies could result in March 2017. No reportreduced sales by the Utility operating companies. Such loss of audit has been issued.
Duesales, due to higher fuel costs forthe methodology used to determine cost of service rates or otherwise, could put upward pressure on rates, possibly resulting in adverse regulatory actions to mitigate such effects on rates. Further, the failure of regulatory structures to evolve to accommodate the changing needs and desires of customers with respect to the sourcing and use of electricity also could diminish sales by the operating monthcompanies. 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 January 2018 resultingreductions 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 part from recent cold weather, higher Henry Hub prices,regulatory proceedings, and an increasesudden or prolonged increases in total fuel and purchased power costs Entergy Louisiana planscould lead to capincreased customer arrearages or bad debt expenses.
The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred or not reflected in rates as permitted by approved rate schedules and accounting rules, including the cost of replacement power purchased when generators experience outages or when planned outages are extended, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs, particularly when there are substantial or sudden increases in such costs. Regulators also may initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
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Entergy Corporation, Utility operating companies, and System Energy
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 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. The Utility operating companies also may experience, and in some instances have experienced, an increase in customer bill arrearages and bad debt expenses due to, among other reasons, increases in fuel and purchased power costs, especially in periods of economic decline or hardship. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power cost recovery, see Note 2 to the financial statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and resource adequacy construct. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell capacity, energy, and/or ancillary services in certain regions and/or the economic value of such sales, or increase 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. Additionally, each Utility operating company’s continued participation in MISO may be affected by the outcomes of proceedings at their respective retail regulators regarding the realized and expected costs and benefits associated with such Utility operating company’s ongoing participation in MISO.
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.
The MISO tariff provisions governing the rights and obligations associated with the resource adequacy construct provided under the MISO tariff are subject to change and have recently undergone significant changes, some of which are the subject of pending litigation and/or appeals. As an example, MISO recently has made
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
changes to its capacity accreditation methodology for thermal resources which emphasizes performance during a very small subset of hours in which the supply of generation capacity needed to serve load is tightest. MISO is now embarking on a larger scale reassessment of its overall accreditation practices, including accreditation of renewable resources. Due to their magnitude and, with respect to the changes already made, the speed with which they have been implemented, these changes carry risk, including compliance risk, and may result in material additional costs being passed through to the Utility operating companies’ customers in retail rates, including but not limited to additional capacity costs incurred in the annual MISO Planning Resource Auction. Also, by virtue of the Utility operating companies’ participation in MISO and the design and terms of the MISO resource adequacy construct, other load-serving entities served by the Utility operating companies’ transmission assets, which are under MISO’s functional control, may be able to circumvent reasonable resource planning obligations and avoid, in whole or in part, the full cost of procuring the resources reasonably needed to reliably supply their respective loads. In particular, the design of the current MISO resource adequacy construct and the absence of a minimum capacity obligation in MISO create a risk of other load-serving entities engaging in “free ridership” through their strategy for participation in the MISO resource adequacy construct and energy and ancillary services markets – specifically, by using energy and ancillary services available from the Utility operating companies’ owned and controlled generating units without paying a reasonable share of the cost of the capacity required to provide such energy and ancillary services. As a result, there are a variety of risks to the Utility operating companies and their customers, including the risk of bearing additional costs for resources needed to ensure reliable service, the risk of reduced reliability and the enhanced risk of outages and lost sales which, because of the methodology for establishing cost of service rates, presents the risk of upward pressure on the Utility operating companies’ rates.
In addition, a large volume of parties and individual generation resources are presently seeking to interconnect to the transmission system MISO administers and over which MISO exercises functional control. Due to the resources and time required to study and evaluate these numerous interconnection requests, including the effects of speculative requests and requests that are withdrawn at late stages of the process, the current MISO interconnection queue to review new requests is subject to significant delays or periods in which MISO does not accept new interconnection requests. These delays present risks to the Utility operating companies and their ability to develop and procure new generation resources to serve their respective loads.
For additional information on MISO regulation and the Utility operating companies’ membership in MISO, see “FederalRegulation of the Utility – Transmission and MISO Markets”section of Part I, Item 1.
Entergy’s and the Utility operating companies’ business, results of operations, and financial condition could be adversely affected by events beyond their control, such as public health crises, natural disasters, geopolitical tensions, or other catastrophic events.
Entergy and the Utility operating companies could be adversely affected by various events beyond their control, including, without limitation, public health crises, natural disasters, geopolitical tensions and other political instability, or other catastrophic events. Any of the foregoing, whether occurring locally, nationally, or globally, and the resulting effects thereof could lead to disruption of the general economy, impacts on the customers of the Utility operating companies, and disruption of the operations of Entergy’s subsidiaries, due to, among other things:
•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;
•adverse impacts on liquidity and cash flows, including through declining sales, reduced revenues, delays in receipts of customer payments, or increased bad debt expense;
•delays in regulatory proceedings;
•regulatory outcomes that require the Utility operating companies to postpone planned investments and otherwise reduce costs due to, for example, the impact of a public health crises or such other catastrophic events on their customers;
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
•workforce availability challenges, including, for example, from infections, health, or safety issues resulting from a public health crisis;
•increased storm recovery costs;
•increased cybersecurity risks as a result of many employees telecommuting;
•volatility in the credit or capital markets (and any related increased cost of capital or any inability to access the capital markets or draw on available credit facilities on favorable terms), which could in turn, cause a decrease in the value of its defined benefit pension or decommissioning trust funds;
•adverse impacts on Entergy’s credit metrics or ratings;
•governmental mandates in response to any such event; or
•other adverse impacts on their ability to execute on business strategies and initiatives.
To the extent any of these events occur, the business, results of operations, and financial condition of Entergy and the Utility operating companies could be adversely affected.
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather, the impact on customer bills of permitted storm cost recovery, or the inability to securitize future storm restoration costs could have material effects on Entergy and its Utility operating companies.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather, including lower credit ratings and, thus, higher costs for future debt issuances. The inability to recover losses either excluded by insurance or in excess of the insurance limits that can be secured economically also could have a material effect on Entergy and its Utility operating companies. In addition, the recovery of major storm restoration costs from customers could effectively limit our ability to make planned capital or other investments due to the impact of such storm cost recovery on customer bills, especially in a rising cost environment.
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, droughts, wildfires, flooding events, or ice storms, the frequency or intensity of which may be exacerbated by climate change, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, criticism or adverse publicity, and reduced customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors including weather and economic conditions, trends in energy efficiency, new technologies, and self-generation alternatives, including the willingness
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
and ability of large industrial customers to develop co-generation facilities that greatly reduce their grid demand. In addition, changes to regulatory policies, such as those that allow customers to directly access the market to procure wholesale energy or those that incentivize development and utilization of new, developing, or alternative sources of generation, could, and in some instances, have reduced sales, and other non-traditional procurements, such as virtual purchase power agreements, could, and in some instances have limited growth opportunities or reduced sales at the Utility operating companies. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and typically do not have a long-lasting effect on Entergy’s operating results. Others, such as the organic turnover of appliances and lighting and their replacement with more efficient ones and adoption of newer technologies, including smart thermostats, new building codes, distributed energy resources, energy storage, demand side management, and rooftop solar, are having a more permanent effect by reducing sales growth rates from historical norms. As a result of these emerging efficiencies and technologies, the Utility operating companies may lose customers or experience lower average use per customer in the residential and commercial classes, and continuing advances have the potential to further limit sales or sales growth in the future.
The Utility operating companies also may face competition from other companies offering products and services to Entergy’s customers. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity markets; however, industrial sales are sensitive to changes in conditions in the markets in which its customers operate. Negative changes in any of these or other factors, particularly sustained economic downturns or sluggishness, have the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity. The Utility operating companies also may not realize anticipated or expected growth in industrial sales, such as 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.
Nuclear Operating, Shutdown, and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies and System Energy are expected to consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies and System Energy. Nuclear plant operations involve substantial fixed operating costs. Consequently, there is pressure on plant owners to operate nuclear power plants at higher capacity factors, though such operations always must be consistent with safety, reliability, and nuclear regulatory requirements. For the Utility operating companies that own nuclear plants, lower nuclear plant capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their owned or contractually controlled facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs.
Certain of the Utility operating companies and System Energy periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months. Plant maintenance and upgrades are often scheduled during such planned outages, which may extend the planned outage duration beyond that required for only refueling activities. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease, and maintenance costs may increase.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 the end of 2027. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past and may be subject to increased volatility due to the imposition of tariffs, domestic purchase requirements, supply chain disruptions, limitations or bans on importation of uranium or uranium products from foreign countries, evolving geopolitical conditions such as the wars between Russia and Ukraine and Israel and Hamas, the Nigerien coup, or shifting trade arrangements or sanctions 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 inherent market uncertainties, as well as uncertainties arising from geopolitical conflicts, 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 uninterrupted 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 or service providers to continue to supply fuel or provide such services at acceptable prices or at all. While such suppliers have performed as expected to date, the future inability of suppliers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies and System Energy.
Certain of the Utility operating companies and System Energy face the risk that the NRC will change or modify its regulations, suspend or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. Interested parties may also intervene in pending proceedings, which could result in prolonged proceedings. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy, certain of the Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the
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change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, and System Energy, see “Regulation of Entergy’s Business- Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process” in Part I, Item 1.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Certain of the Utility operating companies and System Energy are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies and System Energy began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by these Utility operating companies and System Energy in regulatory proceedings should there be a determination of imprudence. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For these Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished, and in some cases, parts are no longer available and have to be reverse-engineered for replacement. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for certain of the Utility operating companies and System Energy.
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies and System Energy, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies and System Energy incur costs for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of the Yucca Mountain repository 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 is in partial breach of 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities, including aging management of fuel storage casks, may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.
Certain of the Utility operating companies and System Energy may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act and/or by Nuclear Electric Insurance Limited (NEIL) in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. As required by the Price-Anderson Act, the Utility operating companies and System Energy carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers, which as of January 1, 2024 is $500 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 $165.9 million per reactor. With 95 reactors currently participating, this translates to a total public liability cap of approximately $15.8 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies and System Energy, regardless of fault or proximity to the incident, will be required to 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 $165.9 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is approximately $830 million). The retrospective premium payment is currently limited to approximately $25 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $165.9 million cap.
NEIL is a utility industry mutual insurance company, owned by its members, including the Utility operating companies and System Energy. NEIL provides onsite property and decontamination coverage. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the NEIL surplus (reserve) be significantly depleted due toinsured losses. As of April 1, 2023, the maximum annual assessment amounts total approximately $70 million for the Utility plants.
As mentioned above, as an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, or System Energy.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
The decommissioning trust fund assets for the nuclear power plants owned by certain of the Utility operating companies and System Energy may not be adequate to meet decommissioning obligations if market performance and other changes decrease the value of assets in the decommissioning trusts, if one or more of Entergy’s nuclear power plants is retired earlier than the anticipated shutdown date, if the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies and System Energy maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies and System Energy collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds.
Under NRC regulations, nuclear plant owners are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount that will be available in each nuclear power plant’s decommissioning trusts combined with any other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used. If the projected amount of each individual plant’s decommissioning trusts exceeds the NRC-required decommissioning amount, then its NRC license termination decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs required to decommission these nuclear power plants, or if funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources or commitments would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of the nuclear generating plant owned by certain of the Utility operating companies or System Energy or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. Such changes also could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. As a result, under any of these circumstances, the results of operations, liquidity, and financial condition of Entergy, certain of the Utility operating companies, or System Energy could be materially affected.
An early plant shutdown (either generally or relative to current expectations), poor investment results, or higher than anticipated decommissioning costs (including as a result of changing regulatory requirements) could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that certain of the Utility operating companies or System Energy may be required to provide significant additional funds or credit support to satisfy regulatory requirements for decommissioning, which, with respect to these Utility operating companies or System Energy, may not be recoverable from customers in a timely fashion or at all.
For further information regarding nuclear decommissioning costs, 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, and Notes 9 and 16 to the financial statements.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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.
Business Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and its Registrant Subsidiaries depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, or to access capital to operate and grow their businesses, and the cost of capital.
Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies. In addition, Entergy’s and the Registrant Subsidiaries’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service area with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, Hurricane Isaac in 2012, Hurricane Laura, Hurricane Delta, and Hurricane Zeta in 2020, and Winter Storm Uri and Hurricane Ida in 2021. The occurrence of one or more contingencies, including an adverse decision or a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, changes in regulation or governmental policy (including tax and trade policy), or other unknown or unforeseen events, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy, the Utility operating companies, and System Energy, which in turn could negatively affect access to the capital markets.
The inability to raise capital on favorable terms, particularly during times of high interest rates and inflation, and uncertainty or reduced liquidity in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Access to capital markets could be restricted and/or borrowing costs could be increased due to certain sources of debt and equity capital being unwilling to invest in offerings to fund fossil fuel projects or companies that are impacted by extreme weather events, that rely on fossil fuels, or that are impacted by risks related to climate change. Factors beyond Entergy’s control may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. These factors include depressed economic conditions, a recession, increasing interest rates, inflation, sanctions, trade restrictions, political instability, war, terrorism, and extreme volatility in the debt, equity, or credit markets. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
raising capital, issue shorter-term securities, and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility, and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.
A downgrade in Entergy’s or its Registrant Subsidiaries’ credit ratings could negatively affect Entergy’s and its Registrant Subsidiaries’ ability to access capital or the cost of such capital and/or could require Entergy or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy and the Registrant Subsidiaries, including each Registrant Subsidiary’s regulatory framework, ability to recover costs and earn returns, storm or climate risk exposure, diversification, and financial strength and liquidity. If one or more rating agencies downgrade Entergy’s or any of the Registrant Subsidiaries’ ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy’s and its subsidiaries’ suppliers and counterparties require sufficient creditworthiness to enter into transactions. If Entergy’s or the Registrant Subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy or its subsidiaries.
The reputation of Entergy or its Registrant Subsidiaries may be materially adversely affected by negative publicity or the inability to meet its stated goals or commitments, among other potential causes.
As with any company, Entergy’s and its Registrant Subsidiaries’ reputations are an important element of their ability to effectively conduct their businesses. Entergy’s and its Registrant Subsidiaries’ reputations could be harmed by a variety of factors, including: failure of a generating asset or supporting infrastructure; failure to restore power after a hurricane or other severe weather event in a manner perceived as timely by regulators or customers; the incurrence of storm restoration costs perceived as excessive by regulators or customers; failure to effectively manage land and other natural resources; real or perceived violations of environmental regulations, including those related to climate change; real or perceived issues with Entergy’s safety culture or work environment; inability to meet their climate or human capital strategy goals, or failure to demonstrate meaningful progress toward such goals; inability to keep their electricity rates stable; inability to provide quality customer service, including timely and accurate billing; involvement in a class-action or other high-profile lawsuit; significant delays in construction projects; occurrence of or responses to cyber attacks, data breaches or physical- or cyber- security vulnerabilities; acts or omissions of Entergy management or acts or omissions of a contractor or other third party working with or for Entergy or its Registrant Subsidiaries, which actually or perceivably reflect negatively on Entergy or its Registrant Subsidiaries; measures taken to offset reductions in demand or to supply rising demand; a significant dispute with one of Entergy’s or its Registrant Subsidiaries’ customers or other stakeholders; or negative political and public sentiment resulting in a significant amount of adverse press coverage and other adverse statements affecting Entergy or its Registrant Subsidiaries.
Addressing any adverse publicity or regulatory scrutiny is time consuming and expensive and, regardless of the factual basis for the assertions being made (or lack thereof), can have a negative impact on the reputations of Entergy or its Registrant Subsidiaries, on the morale and performance of their employees, and on their relationships with their respective regulators, customers, investors, and commercial counterparties. Adverse publicity or regulatory scrutiny may also have a negative impact on Entergy or its Registrant Subsidiaries’ ability to take timely advantage of various business or market opportunities.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Deterioration in Entergy’s or its Registrant Subsidiaries’ reputations may harm Entergy’s or its Registrant Subsidiaries’ relationships with their customers, regulators, and other stakeholders, may increase their cost of doing business, may interfere with its ability to attract and retain a qualified, inclusive, and diverse workforce, may impact Entergy’s or its Registrant Subsidiaries’ ability to raise debt capital, and may potentially lead to the enactment of new laws and regulations, or the modification of existing laws and regulations, that negatively affect the way Entergy or its Registrant Subsidiaries conduct their business, or may have a material adverse effect on their financial condition and results of operations.
Recent U.S. tax legislation may materially adversely affect Entergy’s financial condition, results of operations, and cash flows.
The Tax Cuts and Jobs Act of 2017 significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. The Inflation Reduction Act of 2022 further significantly changed the U.S. Internal Revenue Code by, among other things, enacting a new corporate alternative minimum tax and expanding federal tax credits for clean energy production. The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with Entergy’s own interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. Further, changes in tax legislation or guidance, or uncertainties regarding interpretation of such tax legislation or guidance, could impact interpretation of and negotiations around certain contractual arrangements with counterparties, which could result in unfavorable changes to such arrangements or delays. In addition, the retail regulatory treatment of the expanded tax credits and corporate alternative minimum tax included in the Inflation Reduction Act of 2022 could materially impact Entergy’s future cash flows, and this legislation and pending interpretive guidance could result in unintended consequences not yet identified that could have a material adverse impact on Entergy’s financial results and future cash flows.
Based on initial IRS guidance and current internal forecasts, Entergy and the Registrant Subsidiaries may become subject to the corporate alternative minimum tax included in the Inflation Reduction Act of 2022 beginning in the next two to four years.
The tax rate decrease included in the Tax Cuts and Jobs Act required Entergy to record a regulatory liability for income taxes payable to customers. Such regulatory liability for income taxes is described in Note 3 to the 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 2023, 2022, 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. For further discussion of the effects of the Inflation Reduction Act of 2022, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 3 to the financial statements.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities, which judgment may prove to be incorrect or may be disputed by regulators or 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
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws or interpretive guidance relating thereto, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s and the Registrant Subsidiaries’ results of operations, financial condition, and liquidity. The intended and unintended consequences of recently enacted legislation could have a material adverse impact on Entergy’s financial results and future cash flows. For further information regarding Entergy’s income taxes, see the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and 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 the realization of any anticipated benefits from such transactions.
Entergy and its subsidiaries’ future prospects and results of operations significantly depend on their ability to successfully implement their business strategies, including achieving Entergy’s climate goals and commitments, which are subject to business, regulatory, economic, shareholder activism 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, each of Entergy Louisiana and Entergy New Orleans have entered into purchase and sale agreements to sell their respective regulated natural gas local distribution company businesses to a third-party. 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 disruptions, import tariffs, and other 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 acquisition or disposition of a business could divert management’s attention from other business concerns;
•Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
•Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy and its subsidiaries may not be successful in managing these or any other significant risks that they may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material effect on their business, financial condition, or results of operations.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
The completion of capital projects, including the construction of power generation facilities, and other capital improvements, involve substantial risks. Should such efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating companies’ ability to complete capital projects, including the construction of power generation facilities, or make other capital improvements, such as transmission and distribution infrastructure replacements or upgrades, in a timely and cost-effective manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise, escalating costs for materials, labor, and environmental compliance, reliance on suppliers for timely and satisfactory performance, delays and cost increases, and supply chains and material constraints, including those that may result from major storm events, both within and outside of Entergy’s service area. Delays in obtaining permits, challenges in securing sufficient land for the siting of solar panels and power generation facilities, shortages in materials and qualified labor, levels of public support or opposition, suppliers and contractors not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, further direct and indirect trade and tariff issues, including those associated with imported solar panels, supply chain delays or disruptions, and other events beyond the control of the Utility operating companies may occur that may materially affect the schedule, cost, and performance of these projects. If these projects or other capital improvements are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of the project or new generation needed to meet the reliability needs of customers at the lowest reasonable cost.
For further information regarding capital expenditure plans and other uses of capital in connection with capital projects, including the potential construction and/or purchase of additional generation supply sources within the Utility operating companies’ service areas, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
Failure to attract, retain and manage an appropriately qualified workforce could negatively affect Entergy or its subsidiaries’ results of operations.
Entergy relies on a large and changing workforce, including employees, contractors, and temporary staffing. Certain factors, such as an aging workforce, mismatching of skill sets for current and future needs, failing to appropriately anticipate future workforce needs, workforce impacts from public health concerns, challenges competing with other employers offering fully remote or more flexible work options, rising salary and other labor costs, unavailability of contract resources, and labor disputes and work disruptions 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. 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 specialized 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.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Entergy and its subsidiaries, including the Utility operating companies and System Energy, may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which Entergy’s subsidiaries, including the Utility operating companies and System Energy, operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies and System Energy conduct their operations and make capital expenditures. These laws and regulations also affect how Entergy’s subsidiaries, including the Utility operating companies and System Energy, manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, certain migratory birds and eagles, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies and System Energy to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, Entergy and its subsidiaries, including the Utility operating companies and System Energy, are subject to potential liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies and System Energy and of property potentially contaminated by hazardous substances they generate. The Utility operating companies currently are involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. Entergy’s subsidiaries, including the Utility operating companies and System Energy, have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated emissions from generating plants potentially are subject to increased regulation, controls, and mitigation expenses. In addition, existing environmental regulations and programs promulgated by the EPA often are challenged legally, or are revised or withdrawn by the EPA, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to regulate, or otherwise compel reductions of greenhouse gas emissions, and water availability issues are discussed below.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, including Entergy’s response to climate change, see the “Regulation of Entergy’s Business– Environmental Regulation” section of Part I, Item 1.
Environmental and regulatory obligations intended to combat the effects of climate change, including by compelling greenhouse gas emission reductions or reporting, increasing clean or renewable energy requirements, or placing a price on greenhouse gas emissions, or the achievement of voluntary climate commitments could materially affect the financial condition, results of operations, and liquidity of Entergy and Entergy’s subsidiaries, including the Utility operating companies and System Energy.
In an effort to address climate change concerns, some federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, the EPA, various environmental interest groups, and other organizations have focused considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. The EPA has promulgated regulations controlling greenhouse gas emissions from certain vehicles, and has proposed regulations for new,
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
existing, and significantly modified stationary sources of emissions, including electric generating units. Such regulations continue to evolve. Various states and regions of the U.S. have taken action to establish greenhouse gas limitations and trading programs. In Louisiana, the former Office of the Governor announced in 2020 the creation of a Climate Initiatives Task Force and issued an executive order that established a path to net-zero emissions by 2050, while in 2021, the City Council of New Orleans passed a renewable and clean portfolio standard that sets a goal of net-zero emissions by 2040 and absolute zero emissions by 2050. The impact that continued changes in the governmental response to climate change risk and any judicial interpretation thereof will have on existing and pending environmental laws and regulations related to greenhouse gas emissions currently is unclear.
Developing and implementing plans for compliance with greenhouse gas emissions reduction or reporting or clean/renewable energy requirements, or for achieving voluntary climate commitments can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. The operations of low or non-emitting generating units (such as nuclear units and solar facilities) at lower than expected capacity factors could require increased generation from higher emitting units, thus increasing Entergy’s greenhouse gas emission rate. Moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where Entergy’s subsidiaries, including the Utility operating companies or System Energy, do business. Violations of such requirements may subject the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. Further, real or perceived violations of environmental regulations, including those related to climate change, or inability to meet Entergy’s voluntary climate commitments, could negatively impact Entergy’s reputation or inhibit Entergy’s ability to pursue its decarbonization objectives. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might attempt to deny or defer timely recovery of these costs.
Future changes in regulation or policies governing the reporting or emission of CO2 and other greenhouse gases or mix of generation sources could (i) result in significant additional costs to Entergy’s Utility operating companies, their suppliers, or customers, (ii) make some of Entergy’s electric generating units uneconomical to maintain or operate, (iii) result in the early retirement of generation facilities and stranded costs if Entergy’s Utility operating companies are unable to fully recover the costs and investment in generation, and (iv) increase the difficulty that Entergy and its Utility operating companies have with obtaining or maintaining required environmental regulatory approvals, each of which could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.
In March 2019, Entergy voluntarily set a climate goal to achieve a 50 percent reduction in its carbon emission rate from the year 2000 by 2030. In September 2020, Entergy voluntarily committed to achieving net zero carbon emissions by 2050. In November 2022, Entergy voluntarily set a climate goal to achieve 50 percent carbon-free energy capacity by 2030. Risks to achieving the 2030 and 2050 goals include, among other things, the ability to execute on renewable resource plans, regulatory approvals, customer demand for carbon-free energy that exceeds Entergy’s or its Utility operating companies’ ability to add lower carbon or carbon-free capacity, load growth, potential tariffs, carbon policy and regulation at the federal or state level, including mandates related to reliability standards, and supply chain costs and constraints. Technology research and development, innovation, and advancements in carbon-free generation are also critical to Entergy’s ability to achieve its 2050 commitment. Entergy cannot predict the ultimate impact of achieving these objectives, or the various implementation aspects, on its system reliability, or its results of operations, financial condition, or liquidity.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
The physical effects of climate change could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Potential physical risks from climate change include an increase in sea level, wind and storm surge damages, more frequent or intense hurricanes and wildfires, wetland and barrier island erosion, flooding and changes in weather conditions (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy’s subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, floods, 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.
Due in part to the recent increase in frequency and intensity of major storm activity along the Gulf Coast, Entergy is pursuing 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 significant weather events, to mitigate the cost of restoration of the electric system after major storms or other significant events, to enable more rapid restoration of electricity after major storm or other significant adverse events, and to deliver electricity to critical customers more immediately after such events. These plans are generally subject to approval by the Utility operating companies’ retail regulators and may not be approved in full or at all. 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.
Additionally, prolonged drought conditions and shifting weather patterns resulting from climate change as well as, among other things, buildup of dry vegetation in areas severely impacted by drought may increase the risk of severe wildfire events within the Utility operating companies’ service areas. Catastrophic wildfires occurring in the Utility operating companies’ service areas could give rise to large damage claims against Entergy or its subsidiaries for fire-related losses alleged to be the result of utility practices and/or the failure of electric and other utility equipment and could also cause Entergy or its subsidiaries to suffer reputational harm or face a more challenging operating, political and regulatory environment.
These and other physical changes could result in, among other things, changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy system’s ability to meet peak customer demand, more frequent and longer lasting outages, increased regulatory oversight, criticism or adverse publicity, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s and its subsidiaries’ financial condition, results of operations, and liquidity.
A decline in the continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of Entergy and its subsidiaries.
Water is a vital natural resource that is also critical to Entergy and its subsidiaries. Entergy’s and its subsidiaries’ facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Entergy’s Utility operating companies also own and/or operate hydroelectric facilities. Accordingly, water
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Entergy Corporation, Utility operating companies, and System Energy
availability and quality are critical to Entergy’s and its subsidiaries’ business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy and its subsidiaries secure water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operate under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy and its subsidiaries also obtain and operate in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, saltwater intrusion, and the potential impacts of climate change on the availability of water resources may cause water use restrictions that affect Entergy and its subsidiaries.
The Utility operating companies, System Energy, and Entergy’s non-utility operations may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the NERC, the SERC, and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. In addition, the retail regulators of the Utility operating companies possess the jurisdiction, and in some cases have exercised such jurisdiction, to impose standards governing the reliable operation of the Utility operating companies’ distribution systems, including penalties if these standards are not met. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy’s non-utility operations.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage near-term and medium-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
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 Entergy’s non-utility business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy’s non-utility business.
The hedging and risk management practices of the Utility operating companies and Entergy's non-utility 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 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 benefits 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 has affected and 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 benefits 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 benefits plans, refer to the “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.
The litigation environment in the states in which the Registrant Subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries and related entities are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and customer matters, and injuries and damages issues, among other matters. The states in which Entergy and the Registrant Subsidiaries operate have
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Entergy Corporation, Utility operating companies, and System Energy
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 and sabotage, physical attacks, cyber attacks, system failures, data breaches or other disruptions of Entergy’s and its subsidiaries’ or their suppliers’ infrastructure or technology systems, including disruptions affecting other third parties ultimately connected to Entergy and its subsidiaries or their suppliers through the transmission grid, may adversely affect Entergy’s business and results of operations.
As an operator of critical infrastructure, Entergy and its subsidiaries face a heightened risk of physical attacks or acts or threats of terrorism, cyber attacks, including ransomware attacks, and data breaches, whether as a direct or indirect act against one of Entergy’s generation, transmission or distribution facilities, operations centers, infrastructure, or information technology systems used to manage, monitor, and transport power to customers and perform day-to-day business functions as well as against the systems of critical suppliers and contractors or other third parties interconnected through the grid. Like many businesses and operators of critical infrastructure, Entergy and its subsidiaries and their third-party suppliers have in the past and, will in the future, continue to be subject to cyber attacks, cybersecurity threats and attempts to compromise and penetrate the information technology systems of Entergy and its subsidiaries and disrupt their operations.
Entergy and its subsidiaries operate in a business that requires evolving information technology systems that include sophisticated data collection, processing systems, software, network infrastructure, and other technologies that are becoming more complex and may be subject to mandatory and prescriptive reliability and security standards. The functionality of Entergy’s technology systems depends on its own and its suppliers’ and their contractors’ technology. Suppliers’ and their contractors’ technology systems to which Entergy is connected directly or indirectly support a variety of business processes and activities to store sensitive data, including (i) intellectual property, (ii) proprietary business information, (iii) personally identifiable information of customers, employees, and others, and (iv) data with respect to invoicing and the collection of payments, accounting, procurement, and supply-chain activities. Any significant failure or malfunction of such information technology systems could result in loss of or inappropriate access to data or disruptions of operations.
There have been attacks and threats of attacks on energy infrastructure by cyber actors, including those associated with foreign governments. Further, attacks may become more frequent in the future as technology becomes more prevalent in energy infrastructure. An attack could affect Entergy’s or its subsidiaries’ 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, including threats fueled by artificial intelligence, Entergy’s technology systems remain inherently vulnerable despite implementations and enhancements of the multiple layers of security and controls. In addition, the prevalent use of smartphones, tablets, and other wireless devices, as well as ongoing remote or hybrid work-from-home arrangement for a significant portion of Entergy’s employees and those of its contractors and vendors may also heighten these risks. If Entergy’s or its subsidiaries’ technology systems, or those of critical suppliers or contractors or other third parties interconnected through the grid, 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. We cannot anticipate, detect, or implement fully preventive measures against all cybersecurity threats.
Any such attacks, failures, or data breaches could have a material effect on Entergy’s and the Registrant Subsidiaries’ business, financial condition, results of operations or reputation. Although Entergy and the Registrant
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Entergy Corporation, Utility operating companies, and System Energy
Subsidiaries purchase insurance for cyber attacks and data breaches, such insurance prices have increased substantially, and coverage may not be adequate to cover all losses that might arise in connection with these incidents. Such incidents may also expose Entergy to an increased risk of litigation (and associated damages and fines). For information on our cybersecurity risk management, strategy, and governance, see “Item 1C. Cybersecurity” in Part I, Item 1C.
Entergy and the Registrant Subsidiaries are subject to risks associated with their ability to obtain adequate insurance at acceptable costs.
The global economic cost to insurers resulting from cyber attacks, natural disasters, and other catastrophic events, in addition to an increased focus on climate issues, could have disruptive effects on insurance markets. The availability of insurance capacity may decrease, and the insurance policies that Entergy or the Registrant Subsidiaries are able to obtain may have higher deductibles, higher premiums, and more restrictive terms and conditions. Further, the insurance policies of Entergy or the Registrant Subsidiaries may not cover all of their potential exposures or actual amounts of losses incurred.
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 continued inflationary pressures related to commodity prices, other materials and supplies, and operation and maintenance expenses, including in the areas of labor, health care, and pension costs. The contracts for the construction of certain of the Utility operating companies’ generation facilities also have included, and in the future may include, price adjustment provisions that, subject to certain limitations, may enable the contractor to increase the contract price to reflect increases in certain costs of constructing the facility. These inflationary pressures could impact the ability of Entergy and its subsidiaries to control costs and/or make substantial investments in their businesses, including their ability to recover costs and investments, and to earn their allowed return on equity within frameworks established by their regulators while maintaining affordability of their services for their customers, in addition to having unpredictable effects on Entergy’s customers. Increases in commodity prices, other materials and supplies, and operation and maintenance expenses, including increasing labor costs and costs and funding requirements associated with Entergy's defined benefit retirement plans, health care plans, and other employee benefits, could increase their financing needs and otherwise adversely affect their results of operations, financial condition, and liquidity.
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers taking gas service may adversely affect Entergy New Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges recover fixed costs on a volumetric basis and, thus, are affected by the amount of gas sold to customers. When purchased gas cost charges increase due to higher gas procurement costs, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which, given its relatively smaller size, could adversely affect results of operations. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time when gas is purchased and the time when ultimate recovery from customers occurs.
(Entergy Corporation and System Energy)
System Energy owns and, through an affiliate, operates a single nuclear generating facility, and it is dependent on sales to affiliated companies for all of its revenues. Certain contractual arrangements relating to
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Entergy Corporation, Utility operating companies, and System Energy
System Energy, the affiliated companies, and these revenues are the subject of ongoing litigation and regulatory proceedings. The aggregate amount of refunds claimed in these proceedings, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. In the event of an adverse decision in one or more of these proceedings requiring the payment of substantial additional refunds, System Energy would be required to seek financing to pay such refunds which financing may not be available on terms acceptable to System Energy when required.
System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies (other than Entergy Texas) as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which currently expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies (other than Entergy Texas) 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 (or on appeal from the FERC to the United States Court of Appeals for the Fifth Circuit), 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 two prudence complaints, one 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, and the second challenging the operation and management of Grand Gulf in the 2021-2022 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, after reduction for settlements reached with the MPSC and the APSC (subject in the latter case to approval by the FERC), exceeds the current net book value of System Energy. Entergy Corporation is not obligated to provide funding to System Energy to enable it to pay any such refunds. In the event that an adverse decision in one or more of these proceedings required the payment of substantial additional refunds, System Energy would need to source additional financing to pay such refunds. Such financing may not be available on terms acceptable to System Energy when required. System Energy and its debt securities have been subject to downgrade by rating agencies in the past, most recently in May 2023. Any further downgrade by one or more rating agencies could adversely affect the market prices of System Energy’s debt securities and otherwise adversely affect System Energy’s financial condition.
In addition, an order requiring System Energy to pay substantial additional refunds could result in a default and, in certain cases, acceleration under one or more of System Energy’s existing bond indentures, credit agreements, or other financing arrangements. Certain events constituting events of default under System Energy’s financing agreements may also result in defaults under, or acceleration with respect to, financing arrangements involving certain credit agreement and guarantee obligations of Entergy Corporation.
These proceedings are pending before their respective adjudicators and no final decisions have been reached. Thus, Entergy cannot predict with certainty the outcome of any of these proceedings, or the magnitude of any refunds or rate adjustments, and an adverse outcome in any of them could have a material adverse effect on Entergy’s or System Energy’s results of operations, financial condition, or liquidity. See Note 2 to the financial statements for further discussion of the proceedings. The Utility operating companies (other than Entergy Texas) have agreed to implement certain protocols for providing retail regulators with information regarding rates billed under the Unit Power Sales Agreement.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to certain Entergy System companies’ support of System Energy, see Notes 5 and 8 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
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Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
Entergy’s non-utility operations are subject to substantial governmental regulation and may be adversely affected by legislative, regulatory, or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy’s non-utility operations are subject to regulation under federal, state, and local laws. Compliance with the requirements under these various regulatory regimes may cause Entergy’s non-utility operations to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Entergy’s non-utility operations include legal entities that meet the definition of a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted those entities the authority to sell electricity at market-based rates. The FERC’s orders that grant those entities market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that those entities can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, market-based sales are subject to certain market behavior rules, and if one of those entities were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1.496 million per day per violation. If one of those entities were to lose their market-based rate authority, it would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates those entities charge for power from its facilities.
Entergy’s non-utility operations are also affected by legislative and regulatory changes, as well as by changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operator. The Independent System Operator that oversees the relevant wholesale power market has imposed, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in that market. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of Entergy’s non-utility operations’ generation facilities that sell energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on Entergy’s non-utility operations. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, have raised claims that the competitive marketplace is not working, and have made proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, Entergy’s non-utility operations’ results of operations, financial condition, and liquidity could be materially affected.
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Entergy Corporation, Utility operating companies, and System Energy
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock, and has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its other financial obligations.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation has provided, and may continue to provide, capital contributions or debt financing to its subsidiaries, which would reduce the funds available to meet its financial obligations, including making interest and principal payments on outstanding indebtedness, and to pay dividends on Entergy’s common stock. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The subsidiaries of Entergy Corporation are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make distributions to Entergy Corporation. The ability of such subsidiaries to make payments of dividends or distributions to Entergy 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, LLC 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, LLC and are therefore subject to prior payment of distributions on its preferred securities.
The hazardous activities associated with power generation could adversely impact our results of operations and financial condition.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquakes, floods, lightning, hurricanes and wind, hazards, such as fire, explosion, collapse, and machinery failure, are inherent risks in our operations which may occur as a result of inadequate internal processes, technological flaws, human error, or actions of third parties or other external events. The control and management of these risks depend upon adequate development and training of personnel and on operational procedures, preventative maintenance plans, and specific programs supported by quality control systems, which may not prevent the occurrence and impact of these risks.
The hazards described above, along with other safety hazards associated with our operations, can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury, and fines and/or penalties and may adversely affect our reputation.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Risk Management and Strategy
Entergy and the Registrant Subsidiaries maintain a security-risk-management system with defined roles, duties, governance, and accountability. Under this physical- and cyber-risk model, Entergy and the Registrant Subsidiaries streamline security into a centralized program. The Chief Security Officer (CSO) is responsible for
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
establishing the security and reliability risk strategy, setting policies, monitoring controls and compliance, providing support activities, and reporting on the security program. The Chief Information Security Officer (CISO) is responsible for establishing the cybersecurity strategy and implementing physical and cyber security systems for the security program. The Chief Ethics & Compliance Officer works with the CSO to address requirements of external security-related regulations, and where applicable, incorporate them into business policies. Management is responsible for identifying and managing risk directly through execution of the security program and compliance with security policies. Entergy and the Registrant Subsidiaries’ risk management model addresses compliance with certain regulatory constructs, such as the NERC Reliability Standards, the NRC Code of Federal Regulations, the Payment Card Industry Data Security Standard, and the Health Insurance Portability and Accountability Act, among other regulations. Entergy and the Registrant Subsidiaries’ risk management model continuously evolves to improve and implement protections, controls, and monitoring to mitigate risks to their part of North America’s electric grid, to protect sensitive information, and to maintain secure business operations. Entergy and the Registrant Subsidiaries manage cybersecurity threats as an enterprise risk with close coordination and information sharing with its federal, state, and local partners. Entergy and the Registrant Subsidiaries also engage with local, state, and federal law enforcement agencies on initiatives to share threat information and participate in a wide range of industry collaborations and classified briefings on cybersecurity developments and evolving risks.
Entergy and the Registrant Subsidiaries maintain access-management controls, including a layered multi-factor authentication process for network and system access, and a defense-in-depth security ecosystem that includes advanced threat detection from independent third parties and federal agencies, security logging and monitoring, and independent third-party penetration and vulnerability assessments. Relevant employees and contractors must complete cybersecurity trainings periodically to heighten security and threat awareness, promote best practices, and meet regulatory requirements. Additional multi-layered prevention and detection processes and technologies to mitigate and minimize the effects of cybersecurity risks include email security, continuous monitoring, vulnerability scanning, anti-virus and anti-malware software, backups and recovery strategy, network segregation, third-party security, and information protection.
Entergy and the Registrant Subsidiaries have incorporated certain cyber-specific response protocols and procedures into their Entergy Incident Management System framework for responding to emergency incidents. This includes the Entergy Incident Response Team Plan, which outlines Entergy’s procedures, steps, and responsibilities for preparing for, detecting, containing, and recovering from an incident. The plan details the roles and responsibilities of Entergy’s officers who would be engaged in such a response to an emergency incident, including key questions to be addressed, critical decision points, and sources of key information to support decision-making. Senior management and the Emergency Incident Response Team periodically review and drill on the plan.
As cybersecurity risks continue to evolve with multiple threat vectors, Entergy and the Registrant Subsidiaries maintain a comprehensive security strategy to keep current with the changing threats. To inform this effort, Entergy and the Registrant Subsidiaries utilize the National Institute of Standards and Technology Cybersecurity Framework, which consists of standards, guidelines, and best practices to manage cybersecurity risk across the enterprise. A risk-based approach is used to direct security initiatives to the most significant risks and provide the most value in terms of risk reduction and protection. Entergy and the Registrant Subsidiaries use a vendor risk management program to assess and monitor security risks that arise from third-party vendors. In addition, Entergy and the Registrant Subsidiaries utilize technology and threat intelligence services to assess and continuously monitor the cybersecurity risk of key vendors, as identified through the vendor risk management program.
While Entergy and the Registrant Subsidiaries have experienced cybersecurity incidents, except as otherwise summarized above or discussed elsewhere in this report, the risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected them including their business strategy, results of operations, or financial condition. See “Item 1A. Risk Factors” in Part I, Item 1A for a detailed description of the risks related to cybersecurity.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
Corporate Governance
The Board of Directors is responsible for oversight of the identification, management, and mitigation of enterprise-wide risk, including cybersecurity risk. The Audit Committee has the primary responsibility for overseeing risk management, including oversight of cybersecurity risk management practices and performance. The Audit Committee generally receives reports at each regular quarterly meeting provided by the Chief Information Officer, the CSO, the CISO, and the General Auditor on the cybersecurity management program. The reports focus on the programs and protocols in place to mitigate cybersecurity risks, led by the CSO. Among other things, the reports may include: recent cyber risk and cybersecurity developments; industry engagement activities; legislative and regulatory developments; cyber-risk governance and oversight; selected cyber risk metrics and activities; cyber risk incident response plans and strategies; cybersecurity drills and exercises; assessments by third party experts and Internal Audit; and major projects and initiatives.
While the Board of Directors and Audit Committee oversee cybersecurity risk management, Entergy’s management is responsible for managing cybersecurity risk. Entergy and the Registrant Subsidiaries’ security-risk-management system, as discussed above, is comprised of a three lines of defense model to enhance risk management efforts and define roles in the security program. The first line of defense, comprised of business units performing operational functions, including the CISO, is responsible for identification and management of security and reliability risks directly through design, implementation, and execution of control activities. The second line of defense, comprised of the CSO and Chief Security Office, performs and supports security and reliability risk management and governs and oversees the execution of security and reliability controls by the first line of defense. Ownership of specific security operations may migrate from a business unit in the first line of defense to the second line of defense, as determined to be appropriate by the Chief Security Office. The third line of defense, which includes Internal Audit, independent third parties, and certain regulatory constructs, such as the NERC Reliability Standards and the NRC Cyber Rule, provides assurance of selective actions taken by the first and second lines of defense to senior management and the Board of Directors.
Entergy’s CSO is responsible for overseeing physical, cyber, and reliability risk, including governance, compliance, and threat intelligence. The CSO’s background includes serving as the Global Lead Business Information Security Officer for a multinational pharmaceutical and biotechnology company, Vice President of Cybersecurity Solutions for an international consulting firm, and an operations manager for a multinational technology company. The CSO is also a former intelligence officer in the U.S. Marine Corps, with experience in the Fleet Marine Force, Joint Staff J-2/Defense Intelligence Agency, and Headquarters Marine Corps Command, Control, Communications, and Computers (C4I). The CSO participated in numerous exercises and crisis operations during his time in the military. The CSO is a certified Information Security Manager from the Information Systems Audit and Control Association and a certified Information Privacy Manager from the International Association of Privacy Professionals. The CSO also completed the Harvard Kennedy School Executive Education Program in Cybersecurity and the FBI Domestic Security Executive Academy.
Entergy’s CISO is responsible for enterprise strategic and operational cybersecurity, physical security systems, and regulatory compliance. The CISO oversees investments in tools, resources, and processes that allow for the continuous improvement and maturity of Entergy’s cybersecurity posture. The CISO has expertise spanning more than 25 years in the realm of information technology, information security, and cyber/physical security management. The CISO’s background includes serving as the Vice President and Chief Information Security Officer for an electric utility with responsibility for enterprise cybersecurity covering corporate, electric, nuclear, and gas operations. Additionally, the CISO served as the Chief Security Officer for the Electric Reliability Council of Texas with overall responsibility for its cybersecurity, physical security, and emergency management programs. Her previous experience includes multiple technical, managerial, and strategic roles within industries ranging from energy, telecommunication, software development, and cybersecurity consulting. The CISO is a Certified Information Systems Security Professional, Certified Information Security Manager, and Certified in Risk and Information Systems Control.
Part I Item 1A, 1B, and 1C
Entergy Corporation, Utility operating companies, and System Energy
In the event of a suspected or actual cybersecurity incident, the Security Incident Response Team (SIRT), which includes the CISO, has primary responsibility for initial identification and evaluation of potential business impacts and escalation of the incident’s severity classification using pre-established criteria with a specified communication matrix and escalation thresholds. The Security Incident Commander, which role is served by rotating leaders in the CISO organization, provides tactical leadership and oversight management at the cross-functional level for the incident. The SIRT remains engaged throughout the incident response lifecycle, including detection and analysis, containment, eradication and recovery, and post-incident remediation, and coordinates with the impacted business functions, if warranted. Once a cyber incident is confirmed, the SIRT is responsible for maintaining situational awareness and continuous monitoring of the need for escalation or de-escalation of the incident’s severity classification. As certain escalation thresholds are exceeded, additional levels of management notification are required by the SIRT, including notification of and recurring communication with Entergy’s Incident Response Team, which includes the Chief Executive Officer, the Chief Operating Officer, the CSO, other executive management, and members of the affected business functions. Depending upon the facts, analysis, materiality, and anticipated or current impacts, the Chief Executive Officer and the General Counsel will determine the timing and cadence for communication of the cyber incident with the Board of Directors or Audit Committee.
ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2023 Compared to 2022
Net Income
Net income increased $104 million primarily due to a $159.6 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, higher retail electric price, lower other operation and maintenance expenses, and higher other income. The increase was partially offset by write-offs of $78.4 million ($58.8 million net-of-tax) in third quarter 2023 as a result of Entergy Arkansas’s approved motion to forgo recovery related to the 2013 ANO stator incident, higher interest expense, lower volume/weather, and higher depreciation and amortization expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2023 to 2022:
| | | | | |
| Amount |
| (In Millions) |
| 2022 operating revenues | $2,673.2 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (75.0) | |
| Volume/weather | (31.4) | |
| Retail electric price | 79.6 | |
| 2023 operating revenues | $2,646.4 | |
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 the effect of less favorable weather on residential sales and a decrease in weather-adjusted residential usage, partially offset by an increase in industrial usage. The increase in industrial usage is primarily due to an increase in demand from small industrial customers and 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 January 2023. See Note 2 to the financial statements for further discussion of the 2022 formula rate plan filing.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Arkansas for the years ended December 31, 2023 and 2022 are as follows:
average | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | | |
| Residential | 7,610 | | | 8,147 | | | (7) | |
| Commercial | 5,584 | | | 5,615 | | | (1) | |
| Industrial | 9,095 | | | 8,493 | | | 7 | |
| Governmental | 192 | | | 218 | | | (12) | |
| Total retail | 22,481 | | | 22,473 | | | — | |
| Sales for resale: | | | | | |
| Associated companies | 2,218 | | | 1,906 | | | 16 | |
| Non-associated companies | 5,777 | | | 6,520 | | | (11) | |
| Total | 30,476 | | | 30,899 | | | (1) | |
See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $17.1 million in compensation and benefits costs primarily due toa decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a revision to estimated incentive compensation expense in first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
•a decrease of $10.5 million in transmission costs allocated by MISO;
•the effects of recording a final judgment in first quarter 2023 to resolve claims in the ANO damages case against the DOE related to spent nuclear fuel adjustmentstorage costs. The damages awarded include the reimbursement of approximately $10.3 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $9.6 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022.
The decrease was partially offset by:
•an increase of $10.4 million in contract costs related to operational performance, customer service, and organizational health initiatives;
•an increase of $9.2 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023;
•an increase of $5.2 million in nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022 and higher nuclear labor costs; and
•several individually insignificant items.
Asset write-offs includes the effects of Entergy Arkansas forgoing recovery of identified costs resulting from the 2013 ANO stator incident. In third quarter 2023, Entergy Arkansas recorded write-offs of its regulatory asset for deferred fuel of $68.9 million and the undepreciated balance of $9.5 million in capital costs related to the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
ANO stator incident. See Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income increased primarily due to:
•higher interest earned on money pool investments;
•an increase in the allowance for equity funds used during construction due to be billedhigher construction work in progress in 2023; and
•a decrease in charitable donations in 2023 as compared to 2022.
Interest expense increased primarily due to the issuance of $425 million of 5.15% Series mortgage bonds in January 2023 and higher interest accrued on spent nuclear fuel disposal costs.
The effective income tax rates were (33.3%) for 2023 and 21.6% for 2022. 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.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:
| | | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 | |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $5,278 | | | $12,915 | | | $192,128 | | |
| | | | | | |
| Net cash provided by (used in): | | | | | | |
| Operating activities | 941,021 | | | 699,732 | | | 549,216 | | |
| Investing activities | (1,032,952) | | | (852,794) | | | (898,193) | | |
| Financing activities | 90,285 | | | 145,425 | | | 169,764 | | |
| Net decrease in cash and cash equivalents | (1,646) | | | (7,637) | | | (179,213) | | |
| | | | | | |
| Cash and cash equivalents at end of period | $3,632 | | | $5,278 | | | $12,915 | | |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2023 Compared to 2022
Operating Activities
Net cash flow provided by operating activities increased $241.3 million in 2023 primarily due to:
•lower 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;
•higher collections from customers;
•the refund of $41.7 millionreceived from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. The refund was subsequently applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;
•a decrease of $38.5 million in pension contributions in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding; and
•$23.2 million in proceeds received from the DOE in April 2023 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.
The increase was partially offset by:
•the timing of payments to vendors;
•an increase of $25.4 million in storm spending in 2023 as compared to 2022; and
•an increase of $22.1 million in interest paid.
Investing Activities
Net cash flow used in investing activities increased $180.2 million in 2023 primarily due to:
•an increase of $122.9 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023;
•an increase of $86.6 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Arkansas’s transmission system; and
•an increase of $43.2 million as a result of fluctuations in nuclear fuel activity due to variations from year to year in the timing and pricing of fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle.
The increase was partially offset by:
•a decrease of $38.3 million in nuclear construction expenditures primarily due to decreased spending on various nuclear projects in 2023;
•$17.9 million in proceeds received from the DOE in April 2023 resulting from litigation regarding spent nuclear fuel storage costs that were previously recorded as plant. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
•a decrease of $14.1 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Financing Activities
Net cash flow provided by financing activities decreased $55.1 million in 2023 primarily due to:
•an increase of $331 million in common equity distributions paid in 2023 in order to maintain Entergy Arkansas’s capital structure;
•the repayment, at maturity, of $250 million of 3.05% Series mortgage bonds in June 2023;
•the issuance of $200 million of 4.20% Series mortgage bonds in March 20182022;
•the repayment, at $0.03060 per kWhmaturity, of $40 million of 3.17% Series M notes by the Entergy Arkansas nuclear fuel company variable interest entity in December 2023; and
•money pool activity.
The decrease was partially offset by:
•the issuance of $425 million of 5.15% Series mortgage bonds in January 2023;
•the issuance of $300 million of 5.30% Series mortgage bonds in August 2023;
•net long-term borrowings of $70.2 million in 2023 as compared to net repayments of $4.8 million in 2022 on the nuclear fuel company variable interest entity’s credit facility; and
•an increase of $61.3 million in prepaid deposits related to contributions-in-aid-of-construction primarily for customer and generator interconnection agreements.
Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased $35.4 million in 2023 compared to increasing by $40.9 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Registrant Subsidiaries’ dependence on external short-term borrowings.
See Note 5 to the financial statements for further details of long-term debt.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Capital Structure
Entergy Arkansas’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for Entergy Arkansas is primarily due to the net issuance of long-term debt in 2023.
| | | | | | | | | | | |
| | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 55.5 | % | | 52.5 | % |
| Effect of subtracting cash | — | % | | — | % |
| Net debt to net capital (non-GAAP) | 55.5 | % | | 52.5 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 defer billingcontrol its cost of all fuel costscapital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the cappedextent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced 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.
| | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $1,090 | | | $355 | | | $240 | |
| Transmission | 135 | | | 85 | | | 80 | |
| Distribution | 415 | | | 535 | | | 480 | |
| Utility Support | 65 | | | 65 | | | 65 | |
| Total | $1,705 | | | $1,040 | | | $865 | |
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes investments in generation projects to modernize, decarbonize, and diversify Entergy Arkansas’s portfolio, including Walnut Bend Solar, West Memphis Solar, and Driver Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027-2028 | | After 2028 |
| | (In Millions) |
| Long-term debt (a) | $546 | | | $233 | | | $835 | | | $619 | | | $5,514 | |
| Operating leases (b) | $17 | | | $16 | | | $14 | | | $15 | | | $5 | |
| Finance leases (b) | $5 | | | $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 Arkansas currently expects to contribute approximately $55.1 million to its qualified pension plans and approximately $529 thousand to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Arkansas has $34.5 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.
Renewables
Walnut Bend Solar
In October 2020, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 100 MW Walnut Bend Solar facility is in the public interest. Entergy Arkansas primarily requested cost recovery through the formula rate plan rider. In July 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the resource and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In January 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. The counterparty notified Entergy Arkansas that it was terminating the project, though it was willing to consider an alternative for the site. Entergy Arkansas disputed the right of termination. Negotiations were conducted, including with respect to cost and schedule and to updates arising as a result of the Inflation Reduction Act of 2022. In April 2023, Entergy Arkansas filed an application for an amended certificate of environmental compatibility and public need with the APSC seeking approval by June 2023 for the updates to the cost and schedule that were previously approved by the APSC. In June 2023, Entergy Arkansas, the APSC general staff, and the Arkansas Attorney General filed a unanimous settlement supporting that the approval of the Walnut Bend Solar facility is in the public interest based on the terms
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
in the settlement, including the treatment for the production tax credits associated with the facility. In July 2023, after requesting further testimony and purporting to modify several terms in the settlement and upon rehearing, the APSC approved the settlement largely on the terms submitted, including a 30-year amortization period for the production tax credits. In February 2024, Entergy Arkansas made an initial payment of approximately $169.7 million to acquire the facility. The project will achieve commercial operation once testing is completed and the project has achieved substantial completion. Entergy Arkansas currently expects the project to achieve commercial operation in the first half of 2024, at which time a substantial completion payment of approximately $20 million is expected.
West Memphis Solar
In January 2021, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 180 MW West Memphis Solar facility is in the public interest. In October 2021 the APSC granted Entergy Arkansas’s petition and approved the acquisition of the West Memphis Solar facility and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to file a report within 180 days detailing its efforts to obtain a tax equity partnership. In April 2022, Entergy Arkansas filed its tax equity partnership status report and will file subsequent reports until a tax equity partnership is obtained or a tax equity partnership is no longer sought. In March 2022 the counterparty notified Entergy Arkansas that it was seeking changes to certain terms of the build-own-transfer agreement, including both cost and schedule. In January 2023, Entergy Arkansas filed a supplemental application with the APSC seeking approval for a change in the transmission route and updates to the cost and schedule that were previously approved by the APSC. In March 2023 the APSC approved Entergy Arkansas’s supplemental application. The project is currently expected to achieve commercial operation by the end of 2024.
Driver Solar
In April 2022, Entergy Arkansas filed a petition with the APSC seeking a finding that the purchase of the 250 MW Driver Solar facility is in the public interest and requested cost recovery through the formula rate plan rider. The APSC established a procedural schedule with a hearing scheduled in June 2022, but the parties later agreed to waive the hearing and submit the matter to the APSC for a decision consistent with the filed record. In August 2022 the APSC granted Entergy Arkansas’s petition and approved the acquisition of Driver Solar and cost recovery through the formula rate plan rider. In addition, the APSC directed Entergy Arkansas to inform the APSC as to the status of a tax equity partnership once construction is commenced. The parties are evaluating the effects of certain matters related to the Inflation Reduction Act of 2022, including the viability of a tax equity partnership. The project is expected to achieve commercial operation as early as mid-2024.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
•internally generated funds;
•cash on hand;
•the Entergy system money pool;
•debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
•capital contributions; and
•bank financing under new or existing facilities.
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations,
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | | 2020 |
| (In Thousands) |
| ($145,385) | | ($180,795) | | ($139,904) | | $3,110 |
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 2028. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2024. 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, 2023, 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, 2023, $5.8 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 2025. As of December 31, 2023, $70.2 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 April 2025 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 April 2025. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2025.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Retail Rates
2020 Formula Rate Plan Filing
In July 2020, Entergy Arkansas filed with the APSC its 2020 formula rate plan filing to set its formula rate for the 2021 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2021, as amended through subsequent filings in the proceeding, and a netting adjustment for the historical year 2019. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2021 projected year was 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-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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
of return on common equity for the 2022 projected year was 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 was $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 was 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 was $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 was limited to $72.1 million. In December 2021 the APSC approved the settlement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2022.
2022 Formula Rate Plan Filing
In July 2022, Entergy Arkansas filed with the APSC its 2022 formula rate plan filing to set its formula rate for the 2023 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2023 and a netting adjustment for the historical year 2021. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2023 projected year was 7.40% resulting in a revenue deficiency of $104.8 million. The earned rate of return on common equity for the 2021 historical year was 8.38% resulting in a $15.2 million netting adjustment. The total proposed revenue change for the 2023 projected year and 2021 historical year netting adjustment was $119.9 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 $79.3 million. In October 2022 other parties filed their testimony recommending various adjustments to Entergy Arkansas’s overall proposed revenue deficiency, and Entergy Arkansas filed a response including an update to actual revenues through August 2022, which raised the constraint to $79.8 million. In November 2022, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding. As a result of the settlement agreement, the total revenue change was $102.8 million, including a $87.7 million increase for the 2023 projected year and a $15.2 million netting adjustment. Because Entergy Arkansas’s revenue requirement exceeded the constraint, the resulting increase was limited to $79.8 million. In December 2022 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2023.
2023 Formula Rate Plan Filing
In July 2023, Entergy Arkansas filed with the APSC its 2023 formula rate plan filing to set its formula rate for the 2024 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the projected year 2024 and a netting adjustment for the historical year 2022. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2024 projected year was 8.11% resulting in a revenue deficiency of $80.5 million. The earned rate of return on common equity for the 2022 historical year was 7.29% resulting in a $49.8 million netting adjustment. The total proposed revenue change for the 2024 projected year and 2022 historical year netting adjustment is $130.3 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 $88.6 million. The APSC general staff and intervenors filed their errors and objections in October 2023, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues which lowers the constraint to $87.7 million. Entergy Arkansas filed its rebuttal in October 2023. In October 2023, Entergy Arkansas filed with the APSC a settlement agreement reached with other parties resolving all issues in the proceeding, none of which affected Entergy Arkansas’s requested recovery up to the cap constraint of $87.7 million. The settlement agreement provided for amortization of the approximately $39 million regulatory asset for costs associated with the COVID-19 pandemic over a 10-year period as well as recovery of $34.9 million related to the
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
resolution of the 2016 and 2017 IRS audits from previous tax positions that are no longer uncertain, partially offset by $24.7 million in excess accumulated deferred income taxes from reductions in state income tax rates, each before consideration of their respective tax gross-up. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit and the State of Arkansas corporate income tax rate changes. In December 2023 the APSC approved the settlement agreement as being in the public interest and approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2024.
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, account.including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its upcoming energy cost rate redetermination filing that was made in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude from the redetermination of its 2014 energy cost rate $65.9 million of incremental fuel and replacement energy costs incurred in 2013 as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information was available regarding various claims associated with the ANO stator incident. In February 2014 the APSC approved Entergy Arkansas’s request to retain that amount in its deferred fuel balance. In July 2017, Entergy Arkansas filed for a change in rates pursuant to its formula rate plan rider. In that proceeding, the APSC approved a settlement agreement agreed upon by the parties, including a provision that requires Entergy Arkansas to initiate a regulatory proceeding for the purpose of recovering funds currently withheld from rates and related to the stator incident, including the $65.9 million of deferred fuel and purchased energy costs and costs related to the incremental oversight previously noted, subject to certain timelines and conditions set forth in the settlement agreement. In October 2023, Entergy Arkansas made a commitment to the APSC to make a filing to forgo its opportunity to seek recovery of the incremental fuel and purchased energy expense, among other identified costs, resulting from the ANO stator incident. As a result, in third quarter 2023, Entergy Arkansas recorded a write-off of its regulatory asset for deferred fuel of $68.9 million, which includes interest, related to the ANO stator incident. Consistent with its October 2023 commitment, Entergy Arkansas filed a motion to forgo recovery in November 2023, and the motion was approved by the APSC in December 2023. See “ANO Damage, Outage, and NRC Reviews” in Note 8 to the financial statements for further discussion of the ANO stator incident and the approved motion to forgo recovery. Industrial
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 Commercial Customerspotential 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
Entergy Louisiana’s large industrialArkansas, LLC and commercial customers continually explore waysSubsidiaries
Management’s Financial Discussion and Analysis
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 reduce theirthe 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 particular, cogeneration isMarch 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 option availableadjustment to account for a portion of the increased fuel costs resulting from the February 2021 winter storms. The redetermined rate became effective with the first billing cycle in April 2021 through the normal operation of the tariff.
In March 2022, Entergy Louisiana’sArkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.00959 per kWh to $0.01785 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2021, particularly in the fourth quarter 2021. At the request of the APSC general staff, Entergy Arkansas deferred its request for recovery of $32 million from the under-recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination, unless a request for an interim adjustment to the energy cost recovery rider is necessary. This resulted in a redetermined rate of $0.016390 per kWh, which became effective with the first billing cycle in April 2022 through the normal operation of the tariff. In February 2023 the APSC issued orders initiating proceedings with the utilities under its jurisdiction to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms. With respect to any prudence review of Entergy Arkansas fuel costs, as part of the APSC’s draft report issued in its February 2021 winter storms investigation docket, the APSC included findings that the load shedding plans of the investor-owned utilities and some cooperatives were appropriate and comprehensive, and, further, that Entergy Arkansas’s emergency plan was comprehensive and had a multilayered approach supported by a system-wide response plan, which is considered an industry standard. In September 2023 the APSC issued an order in Entergy Arkansas's company-specific proceeding and found that Entergy Arkansas’s practices during the winter storms were prudent.
In March 2023, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected an increase from $0.01639 per kWh to $0.01883 per kWh. The primary reason for the rate increase is a large under-recovered balance as a result of higher natural gas prices in 2022 and a $32 million deferral related to the February 2021 winter storms consistent with the APSC general staff’s request in 2022. The under-recovered balance included in the filing was partially offset by the proceeds of the $41.7 million refund that System Energy made to Entergy Arkansas in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See “Complaints Against System Energy - Grand Gulf Sale-leaseback Renewal Complaint and Uncertain Tax Position Rate Base Issue” in Note 2 to the financial statements for discussion of the compliance report filed by System Energy with the FERC in January 2023. The redetermined rate of $0.01883 per kWh became effective with the first billing cycle in April 2023 through the normal operation of the tariff.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Opportunity Sales Proceeding
In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.
After a hearing, the ALJ issued an initial decision in December 2010. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. The FERC in its decision established further hearing procedures to quantify the effect of repricing the opportunity sales in accordance with the FERC’s June 2012 decision. The hearing was held in May 2013 and the ALJ issued an initial decision in August 2013. The LPSC, the APSC, the City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that the FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denied Entergy’s request for rehearing and affirmed the FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s August 2013 initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order arguing that payments made by Entergy Arkansas should be reduced as a result of the timing of the LPSC’s approval of certain contracts. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. In September 2017 the FERC issued an order denying the request for rehearing on the issue of whether any payments by Entergy Arkansas to the other Utility operating companies should be reduced due to the timing of the LPSC’s approval of Entergy Arkansas’s wholesale baseload contract with Entergy Louisiana. In November 2017 the FERC issued an order denying all of the remaining requests for rehearing of the April 2016 order. In November 2017, Entergy Services filed a petition for review in the D.C. Circuit of the FERC’s orders in the first two phases of the opportunity sales case. In December 2017 the D.C. Circuit granted Entergy Services’ request to hold the appeal in abeyance pending final resolution of the related proceeding before the FERC. In January 2018 the APSC and the LPSC filed separate petitions for review in the D.C. Circuit, and the D.C. Circuit consolidated the appeals with Entergy Services’ appeal.
The hearing required by the FERC’s April 2016 order was held in May 2017. In July 2017 the ALJ issued an initial decision addressing whether a cap on any reduction due to bandwidth payments was necessary and whether to implement the other adjustments to the calculation methodology. In August 2017 the Utility operating companies, the LPSC, the APSC, and FERC staff filed individual briefs on exceptions challenging various aspects of the initial decision. In September 2017 the Utility operating companies, the LPSC, the APSC, the MPSC, the City Council, and FERC staff filed separate briefs opposing exceptions taken by various parties.
Based on testimony previously submitted in the case and its assessment of the April 2016 FERC orders, in the first quarter 2016, Entergy Arkansas recorded a liability of $87 million, which included interest, for its estimated increased costs and payment to the other Utility operating companies, and a deferred fuel regulatory asset of $75 million. Following its assessment of the course of the proceedings, including the FERC’s denial of rehearing in November 2017 described above, in the fourth quarter 2017, Entergy Arkansas recorded an additional liability of $35 million and a regulatory asset of $31 million.
In October 2018 the FERC issued an order addressing the ALJ’s July 2017 initial decision. The FERC reversed the ALJ’s decision to cap the reduction in Entergy Arkansas’s payment to account for the increased bandwidth payments that Entergy Arkansas made to the other operating companies. The FERC also reversed the ALJ’s decision that Grand Gulf sales from January through September 2000 should be included in the calculation of Entergy Arkansas’s payment. The FERC affirmed on other grounds the ALJ’s rejection of the LPSC’s claim that certain joint account sales should be accounted for as part of the calculation of Entergy Arkansas’s payment. In November 2018 the LPSC requested rehearing of the FERC’s October 2018 decision. In December 2019 the FERC denied the LPSC’s request for rehearing. In January 2020 the LPSC appealed the December 2019 decision to the D.C. Circuit.
In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. No protests were filed in response to the December 2018 compliance filing. 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, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 were appealed to the D.C. Circuit. In February 2020 all of the appeals were consolidated and in April 2020 the D.C. Circuit established a briefing schedule. Briefing was completed in September 2020 and oral argument was heard in December 2020. In July 2021 the D.C. Circuit issued a decision denying all of the petitions for review filed in response to the FERC’s opportunity sales orders.
In February 2019 the LPSC filed a new complaint relating to two issues that were raised in the opportunity sales proceeding, but that, in its October 2018 order, the FERC held were outside the scope of the proceeding. In March 2019, Entergy Services filed an answer and motion to dismiss the new complaint. In November 2019 the FERC issued an order denying the LPSC’s complaint. The order concluded that the settlement agreement approved by the FERC in December 2015 terminating the System Agreement barred the LPSC’s new complaint. In December 2019 the LPSC requested rehearing of the FERC’s November 2019 order, and in July 2020 the FERC issued an order dismissing the LPSC’s request for rehearing. In September 2020 the LPSC appealed to the D.C. Circuit the FERC’s orders dismissing the new opportunity sales complaint. In November 2020 the D.C. Circuit issued an order establishing that briefing will occur in January 2021 through April 2021. Oral argument was held in September 2021. In December 2021 the D.C. Circuit denied the LPSC’s Petition for Review of the new opportunity sales complaint. The opportunity sales cases are complete at FERC and at the D.C. Circuit and no additional refund amounts are owed by Entergy Arkansas.
In May 2019, Entergy Arkansas filed an application and supporting testimony with the APSC requesting approval of a special rider tariff to recover the costs of these payments from its retail customers over a 24-month period. The application requested that the APSC approve the rider to take effect within 30 days or, if suspended by the APSC as allowed by commission rule, approve the rider to take effect in the first billing cycle of the first month occurring 30 days after issuance of the APSC’s order approving the rider. In June 2019 the APSC suspended Entergy Arkansas’s tariff and granted Entergy Arkansas’s motion asking the APSC to establish the proceeding as the single designated proceeding in which interested parties may assert claims related to the appropriate retail rate treatment of the FERC’s October 2018 order and related FERC orders in the opportunity sales proceeding. In January 2020 the APSC adopted a procedural schedule with a hearing in April 2020. In January 2020 the Attorney General and Arkansas Electric Energy Consumers, Inc. filed a joint motion seeking to dismiss Entergy Arkansas’s application alleging that the APSC, in a prior proceeding, ruled on the issues addressed in the application and determined that Entergy Arkansas’s requested relief violates the filed rate doctrine and the prohibition against retroactive ratemaking. Entergy Arkansas responded to the joint motion in February 2020 rebutting these 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
a stay and directed Entergy Arkansas to refund to its retail customers the component of the total FERC-determined opportunity sales payment that was associated with increased bandwidth remedy payments of $13.7 million, plus interest. The refunds were issued in the August 2020 billing cycle. While the APSC denied Entergy Arkansas’s stay request, Entergy Arkansas believes its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, are recoverable. In July 2020, Entergy Arkansas requested rehearing of the APSC order, which rehearing was denied by the APSC in August 2020. In September 2020, Entergy Arkansas filed a complaint in the U.S. District Court for the Eastern District of Arkansas challenging the APSC’s order denying Entergy Arkansas’s request to recover the costs of these payments. In October 2020 the APSC filed a motion to dismiss Entergy Arkansas’s complaint, to which Entergy Arkansas responded. Also in December 2020, Entergy Arkansas and the APSC held a pre-trial conference, and filed a report with the court in January 2021. The court held a hearing in February 2021 regarding issues addressed in the pre-trial conference report, and in June 2021 the court stayed all discovery until it rules on pending motions, after which the court will issue an amended schedule if necessary. In March 2022 the court denied the APSC’s motion to dismiss, and, in April 2022, issued a scheduling order including a trial date in February 2023. In June 2022, Entergy Arkansas filed a motion asserting that it is entitled to summary judgment because Entergy Arkansas’s position that the APSC’s order is pre-empted by the filed rate doctrine and violates the Dormant Commerce Clause is premised on facts that are not subject to genuine dispute. In July 2022, Arkansas Electric Energy Consumers, Inc., an industrial customer base.association, filed a motion to intervene and to hold Entergy Louisiana respondsArkansas’s motion for summary judgment in abeyance pending a ruling on the motion to intervene. Entergy Arkansas filed a consolidated opposition to both motions. In August 2022 the APSC filed a motion for summary judgment arguing that there is no genuine issue as to any material fact and the APSC is entitled to judgment as a matter of law. In September 2022, Entergy Arkansas filed an opposition to the motion. In October 2022 the APSC filed a motion asking the court to hold further proceedings in abeyance pending a decision on the motions for summary judgment filed by workingEntergy Arkansas and the APSC. Also in October 2022, Entergy Arkansas filed an opposition to the motion, and the APSC filed a reply in support of its motion for summary judgment. In January 2023 the judge assigned to the case, on her own motion, identified facts that may present a conflict and recused herself; a new judge was assigned to the case, but he also recused due to a conflict. The case again was reassigned to a new judge. In January 2023 the court denied all pending motions (including those described above) except for a motion by the APSC to exclude certain testimony and further ruled that the matter would proceed to trial. In January 2023, Arkansas Electric Energy Consumers, Inc. filed a notice of appeal of the court’s order denying its motion to intervene to the United States Court of Appeals for the Eighth Circuit and a motion with the district court to stay the proceedings pending the appeal, which was denied. In February 2023, Arkansas Electric Energy Consumers, Inc. filed a motion with the United States Court of Appeals for the Eighth District to stay the proceedings pending the appeal, which also was denied. The trial was held in February 2023. Following the trial, Entergy Arkansas filed a motion with the United States Court of Appeals for the Eighth District to expedite the appeal filed by Arkansas Electric Energy Consumers, Inc. The United States Court of Appeals for the Eighth District granted Entergy Arkansas’s request, and oral arguments were held in June 2023. In August 2023 the United States Court of Appeals for the Eighth District affirmed the order of the court denying Arkansas Electric Energy Consumers, Inc.’s motion to intervene. An order from the district court is pending and is anticipated in 2024.
Net Metering Legislation
An Arkansas law was enacted effective July 2019 that, among other things, expands the definition of a “net metering customer” to include two additional types of customers: (1) customers that lease net metering facilities, subject to certain leasing arrangements, and (2) government entities or other entities exempt from state and federal income taxes that enter into a service contract for a net metering facility. The latter provision allows eligible entities, many of whom are small and large general service customers, to purchase renewable energy directly from third party providers and receive bill credits for these purchases. The APSC was given authority under this law to address certain matters, such as cost shifting and the appropriate compensation for net metered energy and initiated proceedings for this purpose. Because of the size and number of customers eligible under this new law, there is a risk of loss of load and the shifting of costs to customers. A hearing was held in December 2019, with utilities, including Entergy Arkansas, cooperatives, the Arkansas Attorney General, and industrial customers advocating the
Entergy Arkansas, LLC and commercialSubsidiaries
Management’s Financial Discussion and Analysis
need for establishment of a reasonable rate structure that takes into account impacts to non-net metering customers; an additional hearing was conducted in February 2020 for purposes of public comment only. The APSC issued an order in June 2020, and in July 2020 several parties, including Entergy Arkansas, filed for rehearing on multiple grounds, including for the reasons that it imposes an unreasonable rate structure and allows facilities to net meter that do not meet the statutory definition of net metering facilities. After granting the rehearing requests, the APSC issued an order in September 2020 largely upholding its June 2020 order. In October 2020, Entergy Arkansas and several other parties filed an appeal of the APSC’s September 2020 order. In January 2021, Entergy Arkansas, pursuant to an APSC order, filed an updated net metering tariff, which was approved in February 2021. In May 2021, Entergy Arkansas filed a motion to dismiss its pending judicial appeal of the APSC’s September 2020 order on rehearing in the proceeding addressing its net metering rules. In June 2021 the Arkansas Court of Appeals granted the motion and dismissed Entergy Arkansas’s appeal, although other appeals of the September 2020 APSC order remained before the court. In May 2022 the court issued an order affirming the APSC’s decision in part and reversing in part. In June 2022 the APSC sought rehearing from the court with respect to the court’s ruling on a grid charge, which the court of appeals denied in July 2022. One of the cooperative appellants filed a further appeal to the Arkansas Supreme Court in July 2022, which the court decided not to hear.
Separately, as directed by the APSC general staff, the APSC opened a proceeding to compel utilities to amend their net metering tariffs to incorporate the provisions of the legislation that the APSC general staff considered “black letter law.” Entergy Arkansas, the Arkansas Attorney General, and other intervenors opposed this directive pending the development of the rules for implementation that are being considered in the separate net metering rulemaking docket. Nevertheless, reserving its rights, Entergy Arkansas has complied with the directive to amend its tariffs. Asserting procedural and due process violations, in January 2020, Entergy Arkansas and the Arkansas Attorney General separately appealed certain APSC orders in the proceeding. In December 2021 the Arkansas Court of Appeals dismissed the appeal on procedural grounds and without prejudice.
Since the enactment of the net metering legislation, the APSC has approved numerous applications allowing Entergy Arkansas customers to enter into purchase power agreements with third parties and negotiating electric service contracts to provide competitive ratesutilize these purchase power agreements to offset power usage by Entergy Arkansas, despite the lack of proximity between the purchase power agreement and the end-use customer. The APSC also has allowed the aggregation of accounts by net metering customers. These decisions by the APSC have created subsidies in favor of eligible net metering customers to the detriment of non-participating customers. The level of this subsidy continues to grow as additional net metering applications are approved by the APSC.
In August 2022 the APSC opened a rulemaking concerning proposed amendments to the net metering rules to address the expiration on December 31, 2022 of the automatic grandfathering of the existing net metering rate structure. Entergy Arkansas and other utility parties filed initial briefs and comments setting forth that match specific customer needsthe statute imposing the expiration of the automatic grandfathering is not ambiguous and load profiles.that the APSC does not have the authority to extend the grandfathering period, and the hearing was held in October 2022. In December 2022 the APSC issued an order attempting to modify the net metering rules and purporting to allow for the potential for grandfathering after December 31, 2022. More than thirty applicants filed individual net metering applications in December 2022 seeking to be considered under the APSC’s order, although the APSC issued an order in January 2023 holding those applications in abeyance. Several parties, including Entergy Louisiana actively participatesArkansas, sought rehearing, and the Arkansas’s Governor’s executive order limiting new rulemakings calls into question how the APSC’s order to adopt new rules may be effectuated.
In September 2022 the APSC opened another proceeding to investigate the issue of potential cost shifting arising as a result of net metering. Investor owned utilities and some cooperatives were required to make and did make filings in economic development, customer retention,October 2022 with supporting documentation as to the amount and reclamation activitiesextent of cost shifting and the manner in which they would design tariffs to increase industrialrecover those costs on behalf of non-net metering customers. Responses to the utility and commercial demand, from bothcooperative filings were filed in January 2023, and utilities filed their further responses in February 2023.
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
An Arkansas law was enacted effective March 2023 that revises the billing arrangements for net metering facilities in order to reduce the cost shift to non-net metering customers. The new law also imposes a new limit of 5 MW for future net metering facilities, allows utilities to recover net metering credits in the same manner as fuel, and existing customers.grandfathers certain net metering facilities that are online or in process to be online by September 2024. Entergy Arkansas joined other utilities in a motion in April 2023 to close the current APSC docket related to potential cost shifting in light of the new law, and the APSC also canceled the remaining procedural schedule in this docket in April 2023. Because of the new law, in May 2023, the APSC also closed the grandfathering rulemaking that it opened in August 2022. Under the new law, the APSC must approve revisions to the utilities’ tariffs to conform to the new law no later than December 2023. The APSC opened a new rulemaking in April 2023 to consider implementation of the new law and tariffs. In October 2023 the APSC issued new net metering rules to conform to the new law, and utilities, including Entergy Arkansas, filed revised net metering tariffs to comply with the new rules on October 16, 2023. Entergy Arkansas’s revised net metering tariff was approved by the APSC in December 2023.
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Nuclear Matters
Entergy LouisianaArkansas owns and, through an affiliate, operates the River BendANO 1 and Waterford 32 nuclear power plants. Entergy Louisianagenerating plants and is, therefore, subject to the risks related to owningsuch ownership and operating nuclear plants.operation. 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, including the financial requirements to address emerging issues like stress corrosion crackingrelated to equipment reliability, to position Entergy Arkansas’s nuclear fleet to meet its operational goals; the performance and capacity factors of certain materials within the plant systems and the Fukushima event;these nuclear plants; regulatory requirements and potential future regulatory changes, including changes affecting the regulations governing nuclear plant ownership, operations, license renewal and amendments, and decommissioning; the performance and capacity factors of these nuclear plants; the availability of interim or permanent sites for the disposal of spent nuclear fuel and nuclear waste, including the fees charged for such disposal; the sufficiency of nuclear decommissioning trust fund assets and earnings to complete decommissioning of each site when required; and limitations on the amounts and types of insurance commercially availablerecoveries 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 Bendeither ANO 1 or Waterford 3,2, Entergy LouisianaArkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Waterford 3’s ANO 1’s operating license is currently due to expireexpires in December 2024. In March 2016, Entergy Louisiana filed an application with the NRC for an extension of Waterford 3’s2034 and ANO 2’s operating license to 2044. River Bend’s operating license is currently due to expireexpires in August 2025. In May 2017, Entergy Louisiana filed an application with the NRC for an extension of River Bend’s operating license to 2045. In October 2017 an intervenor filed with the NRC a petition to intervene and request for a hearing on the River Bend license renewal application. As provided by NRC procedure, a panel of the Atomic Safety and Licensing Board has been designated to determine whether the intervenor’s three proposed contentions, or allegations of errors or omissions in the license renewal application, are admissible and, if so, to rule on any admitted contentions. In January 2018 the Atomic Safety and Licensing Board denied the petition to intervene and the request for hearing.2038.
Environmental Risks
Entergy Louisiana’sArkansas’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 LouisianaArkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
“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’sArkansas’s financial statements in conformity with generally accepted accounting principlesGAAP 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
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 thethese assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana’sArkansas’s financial position, or results of operations.operations, or cash flows.
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.
Unbilled Revenue
See “Unbilled Revenue” 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 unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets and trust fund investments.
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’sArkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impactedaffected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Costs Sensitivity
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2024 Qualified Pension Cost | | Impact on 2023 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $929 | | $26,189 |
| Rate of return on plan assets | | (0.25%) | | $2,567 | | $— |
| Rate of increase in compensation | | 0.25% | | $985 | | $4,963 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $3,737 | | $54,506 |
| Rate of return on plan assets | | (0.25%) | | $3,309 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,726 | | $8,824 |
Entergy Arkansas, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefitbenefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2024 Postretirement Benefits Cost | | Impact on 2023 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | ($56) | | $3,841 |
| Health care cost trend | | 0.25% | | $217 | | $2,600 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $753 | | $10,727 |
| Health care cost trend | | 0.25% | | $1,219 | | $8,675 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and FundingEmployer Contributions
Total qualified pension cost for Entergy LouisianaArkansas in 20172023 was $44.3 million.$49.5 million, including $26.1 million in settlement costs. Entergy LouisianaArkansas anticipates 20182024 qualified pension cost to be $52.1 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $14.2$19.6 million. Entergy LouisianaArkansas contributed $87.5$54.5 million to its qualified pension plans in 20172023 and estimates pension contributions will be approximately $71.9$55.1 million in 2018,2024, although the 20182024 required pension contributions will be known with more certainty when the January 1, 20182024 valuations are completed, which is expected by April 1, 2018.2024.
Total other postretirement health care and life insurance benefit costsincome for Entergy LouisianaArkansas in 2017 were $12.62023 was $1.9 million. Entergy LouisianaArkansas expects 20182024 postretirement health care and life insurance benefit costsincome of approximately $11.2 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $3.5$5.5 million. Entergy LouisianaArkansas contributed $14.4 million$582 thousand to its other postretirement plans in 20172023 and estimates that 20182024 contributions will be approximately $19 million.$529 thousand.
Federal Healthcare LegislationOther Contingencies
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare LegislationContingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See the “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 membersmember and Board of Directors of
Entergy Louisiana,Arkansas, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Louisiana,Arkansas, LLC and Subsidiaries (the “Company”) as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, comprehensive income, cash flows and changes in equity (pages 349336 through 354340 and applicable items in pages 5547 through 230)238), for each of the three years in the period ended December 31, 2017,2023, 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, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters — Entergy Arkansas, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arkansas Public Service Commission (the “APSC”), which has jurisdiction with respect to the rates of electric companies in Arkansas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the APSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the APSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the 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 APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the APSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities 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 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 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 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 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 APSC and the FERC and orders issued, 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 to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 201823, 2024
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $2,646,396 | | | $2,673,194 | | | $2,338,590 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 514,885 | | | 640,344 | | | 347,166 | |
| Purchased power | | 257,890 | | | 201,726 | | | 280,504 | |
| Nuclear refueling outage expenses | | 59,973 | | | 53,438 | | | 51,141 | |
| Other operation and maintenance | | 737,649 | | | 754,293 | | | 687,418 | |
| Asset write-offs | | 78,434 | | | — | | | — | |
| Decommissioning | | 87,321 | | | 82,326 | | | 77,696 | |
| Taxes other than income taxes | | 141,502 | | | 136,565 | | | 127,249 | |
| Depreciation and amortization | | 400,944 | | | 386,272 | | | 361,479 | |
| Other regulatory charges (credits) - net | | (87,409) | | | (89,418) | | | (31,501) | |
| TOTAL | | 2,191,189 | | | 2,165,546 | | | 1,901,152 | |
| | | | | | |
| OPERATING INCOME | | 455,207 | | | 507,648 | | | 437,438 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 20,587 | | | 17,787 | | | 15,273 | |
| Interest and investment income | | 25,024 | | | 19,554 | | | 76,953 | |
| Miscellaneous - net | | (23,216) | | | (27,348) | | | (22,278) | |
| TOTAL | | 22,395 | | | 9,993 | | | 69,948 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 188,232 | | | 150,928 | | | 140,348 | |
| Allowance for borrowed funds used during construction | | (8,270) | | | (7,070) | | | (6,641) | |
| TOTAL | | 179,962 | | | 143,858 | | | 133,707 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 297,640 | | | 373,783 | | | 373,679 | |
| | | | | | |
| Income taxes | | (99,210) | | | 80,896 | | | 75,195 | |
| | | | | | |
| NET INCOME | | 396,850 | | | 292,887 | | | 298,484 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (5,231) | | | (4,358) | | | (18,092) | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $402,081 | | | $297,245 | | | $316,576 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $4,246,020 |
| |
| $4,126,343 |
| |
| $4,361,524 |
|
| Natural gas | | 54,530 |
| | 50,705 |
| | 55,622 |
|
| TOTAL | | 4,300,550 |
| | 4,177,048 |
| | 4,417,146 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 912,060 |
| | 804,433 |
| | 850,869 |
|
| Purchased power | | 980,070 |
| | 890,058 |
| | 1,129,910 |
|
| Nuclear refueling outage expenses | | 52,074 |
| | 51,361 |
| | 44,480 |
|
| Other operation and maintenance | | 969,400 |
| | 923,779 |
| | 997,546 |
|
| Decommissioning | | 49,457 |
| | 46,944 |
| | 43,445 |
|
| Taxes other than income taxes | | 175,359 |
| | 165,665 |
| | 167,966 |
|
| Depreciation and amortization | | 467,369 |
| | 451,290 |
| | 437,036 |
|
| Other regulatory charges (credits) - net | | (152,080 | ) | | 44,131 |
| | 27,562 |
|
| TOTAL | | 3,453,709 |
| | 3,377,661 |
| | 3,698,814 |
|
| | | | | | | |
| OPERATING INCOME | | 846,841 |
| | 799,387 |
| | 718,332 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 51,485 |
| | 27,925 |
| | 19,192 |
|
| Interest and investment income | | 164,550 |
| | 154,778 |
| | 150,168 |
|
| Miscellaneous - net | | (11,960 | ) | | (11,597 | ) | | (13,190 | ) |
| TOTAL | | 204,075 |
| | 171,106 |
| | 156,170 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 275,185 |
| | 273,283 |
| | 259,894 |
|
| Allowance for borrowed funds used during construction | | (25,914 | ) | | (14,571 | ) | | (10,702 | ) |
| TOTAL | | 249,271 |
| | 258,712 |
| | 249,192 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 801,645 |
| | 711,781 |
| | 625,310 |
|
| | | | | | | |
| Income taxes | | 485,298 |
| | 89,734 |
| | 178,671 |
|
| | | | | | | |
| NET INCOME | | 316,347 |
| | 622,047 |
| | 446,639 |
|
| | | | | | | |
| Preferred distribution requirements and other | | — |
| | — |
| | 5,737 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $316,347 |
| |
| $622,047 |
| |
| $440,902 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $396,850 | | | $292,887 | | | $298,484 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 556,780 | | | 532,291 | | | 503,539 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (102,070) | | | 78,958 | | | 100,459 | |
| Asset write-offs | | 78,434 | | | — | | | — | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | (84,428) | | | (73,579) | | | 17,682 | |
| Fuel inventory | | (6,351) | | | (252) | | | (7,081) | |
| Accounts payable | | (69,947) | | | 64,944 | | | 27,967 | |
| Taxes accrued | | 4,625 | | | 10,936 | | | 7,753 | |
| Interest accrued | | 16,554 | | | 1,708 | | | (5,637) | |
| Deferred fuel costs | | 228,021 | | | (31,009) | | | (162,458) | |
| Other working capital accounts | | (29,690) | | | (29,789) | | | (53,343) | |
| Provisions for estimated losses | | (21,039) | | | 2,914 | | | 6,915 | |
| Regulatory assets | | (6,197) | | | (120,603) | | | 142,706 | |
| Other regulatory liabilities | | 240,762 | | | (264,054) | | | 21,066 | |
| | | | | | |
| Pension and other postretirement liabilities | | (109,077) | | | (67,783) | | | (175,863) | |
| Other assets and liabilities | | (152,206) | | | 302,163 | | | (172,973) | |
| Net cash flow provided by operating activities | | 941,021 | | | 699,732 | | | 549,216 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (946,244) | | | (785,168) | | | (722,628) | |
| Allowance for equity funds used during construction | | 20,587 | | | 17,787 | | | 15,273 | |
| Nuclear fuel purchases | | (137,616) | | | (98,635) | | | (84,302) | |
| Proceeds from sale of nuclear fuel | | 32,937 | | | 37,198 | | | 16,279 | |
| | | | | | |
| Proceeds from nuclear decommissioning trust fund sales | | 117,123 | | | 248,191 | | | 530,628 | |
| Investment in nuclear decommissioning trust funds | | (139,280) | | | (269,497) | | | (524,783) | |
| Payment for purchase of assets | | — | | | (1,044) | | | (131,770) | |
| Change in money pool receivable - net | | — | | | — | | | 3,110 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 17,933 | | | — | | | — | |
| | | | | | |
| | | | | | |
| Decrease (increase) in other investments | | 1,608 | | | (1,626) | | | — | |
| Net cash flow used in investing activities | | (1,032,952) | | | (852,794) | | | (898,193) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,093,253 | | | 232,731 | | | 719,284 | |
| Retirement of long-term debt | | (597,720) | | | (28,521) | | | (728,917) | |
| | | | | | |
| Capital contributions from noncontrolling interest | | — | | | — | | | 51,202 | |
| | | | | | |
| Changes in money pool payable - net | | (35,410) | | | 40,891 | | | 139,904 | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (417,000) | | | (86,000) | | | (50,000) | |
| | | | | | |
| Other | | 47,162 | | | (13,676) | | | 38,291 | |
| Net cash flow provided by financing activities | | 90,285 | | | 145,425 | | | 169,764 | |
| Net decrease in cash and cash equivalents | | (1,646) | | | (7,637) | | | (179,213) | |
| Cash and cash equivalents at beginning of period | | 5,278 | | | 12,915 | | | 192,128 | |
| Cash and cash equivalents at end of period | | $3,632 | | | $5,278 | | | $12,915 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $169,173 | | | $147,060 | | | $143,561 | |
| Income taxes | | $2,705 | | | ($2,753) | | | ($18,933) | |
| Noncash investing activities: | | | | | | |
| Accrued construction expenditures | | $36,264 | | | $93,189 | | | $35,616 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| Net Income | |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
| | | | | | | |
| Other comprehensive income | | |
| | |
| | |
|
| Pension and other postretirement liabilities | | |
| | |
| | |
|
| (net of tax expense of $234, $5,034, and $14,316) | | 2,042 |
| | 7,970 |
| | 22,811 |
|
| Other comprehensive income | | 2,042 |
| | 7,970 |
| | 22,811 |
|
| | | | | | | |
| Comprehensive Income | |
| $318,389 |
| |
| $630,017 |
| |
| $469,450 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $520 | | | $1,911 | |
| Temporary cash investments | | 3,112 | | | 3,367 | |
| Total cash and cash equivalents | | 3,632 | | | 5,278 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 157,520 | | | 140,513 | |
| Allowance for doubtful accounts | | (7,182) | | | (6,528) | |
| Associated companies | | 124,672 | | | 45,336 | |
| Other | | 89,532 | | | 101,096 | |
| Accrued unbilled revenues | | 117,119 | | | 116,816 | |
| Total accounts receivable | | 481,661 | | | 397,233 | |
| | | | |
| Deferred fuel costs | | — | | | 139,739 | |
| Fuel inventory - at average cost | | 57,495 | | | 51,144 | |
| Materials and supplies - at average cost | | 358,302 | | | 288,260 | |
| Deferred nuclear refueling outage costs | | 35,463 | | | 56,443 | |
| | | | |
| | | | |
| Prepayments and other | | 40,866 | | | 26,576 | |
| | | | |
| TOTAL | | 977,419 | | | 964,673 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Decommissioning trust funds | | 1,414,009 | | | 1,199,860 | |
| | | | |
| Other | | 801 | | | 2,414 | |
| TOTAL | | 1,414,810 | | | 1,202,274 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 14,821,814 | | | 14,077,844 | |
| | | | |
| Construction work in progress | | 340,601 | | | 417,244 | |
| Nuclear fuel | | 213,722 | | | 176,174 | |
| TOTAL UTILITY PLANT | | 15,376,137 | | | 14,671,262 | |
| Less - accumulated depreciation and amortization | | 6,002,203 | | | 5,729,304 | |
| UTILITY PLANT - NET | | 9,373,934 | | | 8,941,958 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 1,885,361 | | | 1,810,281 | |
| Deferred fuel costs | | — | | | 68,883 | |
| Other | | 21,334 | | | 18,507 | |
| TOTAL | | 1,906,695 | | | 1,897,671 | |
| | | | |
| TOTAL ASSETS | | $13,672,858 | | | $13,006,576 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 621,018 |
| | 620,211 |
| | 593,635 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 575,804 |
| | 178,549 |
| | 97,461 |
|
| Changes in working capital: | | |
| | |
| | |
|
| Receivables | | (53,829 | ) | | (102,200 | ) | | (12,795 | ) |
| Fuel inventory | | 11,010 |
| | (2,693 | ) | | (887 | ) |
| Accounts payable | | 58,880 |
| | (36,720 | ) | | 23,641 |
|
| Prepaid taxes and taxes accrued | | 128,261 |
| | (235,246 | ) | | 105,687 |
|
| Interest accrued | | (70 | ) | | 1,218 |
| | 2,933 |
|
| Deferred fuel costs | | 23,236 |
| | (17,023 | ) | | 4,222 |
|
| Other working capital accounts | | (30,911 | ) | | 6,462 |
| | (41,890 | ) |
| Changes in provisions for estimated losses | | (8,324 | ) | | 490 |
| | (8,946 | ) |
| Changes in other regulatory assets | | 492,696 |
| | 57,579 |
| | 130,762 |
|
| Changes in other regulatory liabilities | | 605,453 |
| | 62,351 |
| | 96,234 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | (1,207,808 | ) | | — |
| | — |
|
| Changes in pension and other postretirement liabilities | | (32,309 | ) | | (52,559 | ) | | (98,695 | ) |
| Other | | (161,909 | ) | | (64,554 | ) | | (182,485 | ) |
| Net cash flow provided by operating activities | | 1,337,545 |
| | 1,037,912 |
| | 1,155,516 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (1,662,835 | ) | | (1,030,416 | ) | | (845,227 | ) |
| Allowance for equity funds used during construction | | 51,485 |
| | 27,925 |
| | 19,192 |
|
| Insurance proceeds | | 5,305 |
| | 10,564 |
| | — |
|
| Nuclear fuel purchases | | (197,829 | ) | | (73,618 | ) | | (244,040 | ) |
| Proceeds from the sale of nuclear fuel | | 42,634 |
| | 63,304 |
| | 54,595 |
|
| Payment for purchase of plant | | — |
| | (474,670 | ) | | — |
|
| Payments to storm reserve escrow account | | (2,110 | ) | | (1,063 | ) | | (308 | ) |
| Receipts from storm reserve escrow account | | 8,835 |
| | — |
| | — |
|
| Changes in securitization account | | 880 |
| | 351 |
| | (137 | ) |
| Proceeds from nuclear decommissioning trust fund sales | | 231,293 |
| | 219,182 |
| | 123,474 |
|
| Investment in nuclear decommissioning trust funds | | (266,592 | ) | | (257,209 | ) | | (158,028 | ) |
| Changes in money pool receivable - net | | 11,330 |
| | (16,349 | ) | | (3,339 | ) |
| Proceeds from sale of assets | | — |
| | — |
| | 59,610 |
|
| Payment for purchase of assets | | (9,805 | ) | | — |
| | — |
|
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — |
| | 57,934 |
| | — |
|
| Net cash flow used in investing activities | | (1,787,409 | ) | | (1,474,065 | ) | | (994,208 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 733,344 |
| | 2,450,063 |
| | 77,172 |
|
| Retirement of long-term debt | | (407,736 | ) | | (1,488,870 | ) | | (180,595 | ) |
| Redemption of preferred membership interests | | — |
| | — |
| | (110,286 | ) |
| Changes in credit borrowings - net | | 39,746 |
| | (56,562 | ) | | 14,322 |
|
| Distributions paid: | | |
| | |
| | |
|
| Common equity | | (91,250 | ) | | (285,500 | ) | | (226,000 | ) |
| Preferred membership interests | | — |
| | — |
| | (6,082 | ) |
| Other | | (2,183 | ) | | (4,230 | ) | | (15,253 | ) |
| Net cash flow provided by (used in) financing activities | | 271,921 |
| | 614,901 |
| | (446,722 | ) |
| Net increase (decrease) in cash and cash equivalents | | (177,943 | ) | | 178,748 |
| | (285,414 | ) |
| Cash and cash equivalents at beginning of period | | 213,850 |
| | 35,102 |
| | 320,516 |
|
| Cash and cash equivalents at end of period | |
| $35,907 |
| |
| $213,850 |
| |
| $35,102 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $266,871 |
| |
| $324,456 |
| |
| $243,745 |
|
| Income taxes | |
| ($234,199 | ) | |
| $156,605 |
| |
| $89,124 |
|
| Non-cash financing activities: | | | | | | |
| Capital contribution from parent | |
| $— |
| |
| $— |
| |
| ($267,826 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $375,000 | | | $290,000 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 225,344 | | | 276,362 | |
| Other | | 215,502 | | | 310,339 | |
| Customer deposits | | 113,186 | | | 102,799 | |
| Taxes accrued | | 105,151 | | | 100,526 | |
| | | | |
| Interest accrued | | 35,370 | | | 18,816 | |
| Deferred fuel costs | | 88,282 | | | — | |
| | | | |
| Other | | 55,683 | | | 43,394 | |
| TOTAL | | 1,213,518 | | | 1,142,236 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 1,437,053 | | | 1,498,234 | |
| Accumulated deferred investment tax credits | | 27,270 | | | 28,472 | |
| Regulatory liability for income taxes - net | | 392,496 | | | 435,157 | |
| Other regulatory liabilities | | 759,181 | | | 475,758 | |
| Decommissioning | | 1,560,057 | | | 1,472,736 | |
| Accumulated provisions | | 58,959 | | | 79,998 | |
| Pension and other postretirement liabilities | | 8,901 | | | 118,020 | |
| Long-term debt | | 4,298,080 | | | 3,876,500 | |
| Other | | 156,673 | | | 97,650 | |
| TOTAL | | 8,698,670 | | | 8,082,525 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 3,739,071 | | | 3,753,990 | |
| Noncontrolling interest | | 21,599 | | | 27,825 | |
| TOTAL | | 3,760,670 | | | 3,781,815 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $13,672,858 | | | $13,006,576 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $5,836 |
| |
| $49,972 |
|
| Temporary cash investments | | 30,071 |
| | 163,878 |
|
| Total cash and cash equivalents | | 35,907 |
| | 213,850 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 254,308 |
| | 213,517 |
|
| Allowance for doubtful accounts | | (8,430 | ) | | (6,277 | ) |
| Associated companies | | 143,524 |
| | 155,794 |
|
| Other | | 60,893 |
| | 54,186 |
|
| Accrued unbilled revenues | | 153,118 |
| | 159,176 |
|
| Total accounts receivable | | 603,413 |
| | 576,396 |
|
| Fuel inventory | | 39,728 |
| | 50,738 |
|
| Materials and supplies - at average cost | | 299,881 |
| | 294,421 |
|
| Deferred nuclear refueling outage costs | | 65,711 |
| | 22,535 |
|
| Prepaid taxes | | — |
| | 110,104 |
|
| Prepayments and other | | 34,035 |
| | 41,687 |
|
| TOTAL | | 1,078,675 |
| | 1,309,731 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Investment in affiliate preferred membership interests | | 1,390,587 |
| | 1,390,587 |
|
| Decommissioning trust funds | | 1,312,073 |
| | 1,140,707 |
|
| Storm reserve escrow account | | 284,759 |
| | 291,485 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 245,255 |
| | 217,494 |
|
| Other | | 18,999 |
| | 28,844 |
|
| TOTAL | | 3,251,673 |
| | 3,069,117 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 19,678,536 |
| | 18,827,532 |
|
| Natural gas | | 191,899 |
| | 172,816 |
|
| Construction work in progress | | 1,281,452 |
| | 670,201 |
|
| Nuclear fuel | | 337,402 |
| | 249,807 |
|
| TOTAL UTILITY PLANT | | 21,489,289 |
| | 19,920,356 |
|
| Less - accumulated depreciation and amortization | | 8,703,047 |
| | 8,420,596 |
|
| UTILITY PLANT - NET | | 12,786,242 |
| | 11,499,760 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | — |
| | 470,480 |
|
| Other regulatory assets (includes securitization property of $71,367 as of December 31, 2017 and $92,951 as of December 31, 2016) | | 1,145,842 |
| | 1,168,058 |
|
| Deferred fuel costs | | 168,122 |
| | 168,122 |
|
| Other | | 18,310 |
| | 16,003 |
|
| TOTAL | | 1,332,274 |
| | 1,822,663 |
|
| | | | | |
| TOTAL ASSETS | |
| $18,448,864 |
| |
| $17,701,271 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2023, 2022, and 2021 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2020 | $— | | | $3,276,169 | | | $3,276,169 | |
| Net income (loss) | (18,092) | | | 316,576 | | | 298,484 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (50,000) | | | (50,000) | |
| | | | | |
| | | | | |
| Capital contributions from noncontrolling interest | 51,202 | | | — | | | 51,202 | |
| | | | | |
| Balance at December 31, 2021 | $33,110 | | | $3,542,745 | | | $3,575,855 | |
| Net income (loss) | (4,358) | | | 297,245 | | | 292,887 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (86,000) | | | (86,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (927) | | | — | | | (927) | |
| | | | | |
| Balance at December 31, 2022 | $27,825 | | | $3,753,990 | | | $3,781,815 | |
| Net income (loss) | (5,231) | | | 402,081 | | | 396,850 | |
| | | | | |
| | | | | |
| Common equity distributions | — | | | (417,000) | | | (417,000) | |
| | | | | |
| | | | | |
| | | | | |
| Distributions to noncontrolling interest | (995) | | | — | | | (995) | |
| | | | | |
| Balance at December 31, 2023 | $21,599 | | | $3,739,071 | | | $3,760,670 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
|
| | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $675,002 |
| |
| $200,198 |
|
| Short-term borrowings | | 43,540 |
| | 3,794 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 126,685 |
| | 82,106 |
|
| Other | | 404,374 |
| | 358,741 |
|
| Customer deposits | | 150,623 |
| | 148,601 |
|
| Taxes accrued | | 18,157 |
| | — |
|
| Interest accrued | | 75,528 |
| | 75,598 |
|
| Deferred fuel costs | | 71,447 |
| | 48,211 |
|
| Other | | 79,037 |
| | 80,013 |
|
| TOTAL | | 1,644,393 |
| | 997,262 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 2,050,371 |
| | 2,691,118 |
|
| Accumulated deferred investment tax credits | | 121,870 |
| | 126,741 |
|
| Regulatory liability for income taxes - net | | 725,368 |
| | — |
|
| Other regulatory liabilities | | 761,059 |
| | 880,974 |
|
| Decommissioning | | 1,140,461 |
| | 1,082,685 |
|
| Accumulated provisions | | 302,448 |
| | 310,772 |
|
| Pension and other postretirement liabilities | | 748,384 |
| | 780,278 |
|
| Long-term debt (includes securitization bonds of $77,736 as of December 31, 2017 and $99,217 as of December 31, 2016) | | 5,469,069 |
| | 5,612,593 |
|
| Other | | 176,637 |
| | 137,039 |
|
| TOTAL | | 11,495,667 |
| | 11,622,200 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| EQUITY | | |
| | |
|
| Member’s equity | | 5,355,204 |
| | 5,130,251 |
|
| Accumulated other comprehensive loss | | (46,400 | ) | | (48,442 | ) |
| TOTAL | | 5,308,804 |
| | 5,081,809 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $18,448,864 |
| |
| $17,701,271 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | | | |
| | | | Common Equity | | |
| | Preferred Membership Interests | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2014 |
| $110,000 |
| |
| $4,316,210 |
| |
| ($79,223 | ) | |
| $4,346,987 |
|
| Net income | — |
| | 446,639 |
| | — |
| | 446,639 |
|
| Other comprehensive income | — |
| | — |
| | 22,811 |
| | 22,811 |
|
| Preferred stock redemption | (110,000 | ) | | — |
| | — |
| | (110,000 | ) |
| Non-cash contribution from parent | — |
| | 267,826 |
| | — |
| | 267,826 |
|
| Distributions to parent | — |
| | (226,000 | ) | | — |
| | (226,000 | ) |
| Distributions declared on preferred membership interests | — |
| | (5,737 | ) | | — |
| | (5,737 | ) |
| Other | — |
| | (5,214 | ) | | — |
| | (5,214 | ) |
| Balance at December 31, 2015 |
| $— |
| |
| $4,793,724 |
| |
| ($56,412 | ) | |
| $4,737,312 |
|
| Net income | — |
| | 622,047 |
| | — |
| | 622,047 |
|
| Other comprehensive income | — |
| | — |
| | 7,970 |
| | 7,970 |
|
| Distributions to parent | — |
| | (285,500 | ) | | — |
| | (285,500 | ) |
| Other | — |
| | (20 | ) | | — |
| | (20 | ) |
| Balance at December 31, 2016 |
| $— |
| |
| $5,130,251 |
| |
| ($48,442 | ) | |
| $5,081,809 |
|
| Net income | — |
| | 316,347 |
| | — |
| | 316,347 |
|
| Other comprehensive income | — |
| | — |
| | 2,042 |
| | 2,042 |
|
| Distributions declared on common equity | — |
| | (91,250 | ) | | — |
| | (91,250 | ) |
| Other | — |
| | (144 | ) | | — |
| | (144 | ) |
| Balance at December 31, 2017 |
| $— |
| |
| $5,355,204 |
| |
| ($46,400 | ) | |
| $5,308,804 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $4,300,550 |
| |
| $4,177,048 |
| |
| $4,417,146 |
| |
| $4,740,504 |
| |
| $4,399,511 |
|
| Net income |
| $316,347 |
| |
| $622,047 |
| |
| $446,639 |
| |
| $446,022 |
| |
| $414,126 |
|
| Total assets |
| $18,448,864 |
| |
| $17,701,271 |
| |
| $16,387,447 |
| |
| $16,423,825 |
| |
| $15,275,863 |
|
| Long-term obligations (a) |
| $5,469,069 |
| |
| $5,612,593 |
| |
| $4,806,790 |
| |
| $4,882,813 |
| |
| $4,383,273 |
|
| | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt).
| | | | |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $1,198 |
| |
| $1,196 |
| |
| $1,292 |
| |
| $1,358 |
| |
| $1,304 |
|
| Commercial | 956 |
| | 930 |
| | 989 |
| | 1,044 |
| | 1,003 |
|
| Industrial | 1,534 |
| | 1,350 |
| | 1,420 |
| | 1,569 |
| | 1,457 |
|
| Governmental | 69 |
| | 67 |
| | 67 |
| | 70 |
| | 68 |
|
| Total retail | 3,757 |
| | 3,543 |
| | 3,768 |
| | 4,041 |
| | 3,832 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 278 |
| | 368 |
| | 406 |
| | 427 |
| | 320 |
|
| Non-associated companies | 64 |
| | 50 |
| | 36 |
| | 80 |
| | 48 |
|
| Other | 147 |
| | 165 |
| | 152 |
| | 121 |
| | 140 |
|
| Total |
| $4,246 |
| |
| $4,126 |
| |
| $4,362 |
| |
| $4,669 |
| |
| $4,340 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | |
| | |
| | |
| | |
| | |
|
| Residential | 13,357 |
| | 13,810 |
| | 14,399 |
| | 14,415 |
| | 14,026 |
|
| Commercial | 11,342 |
| | 11,478 |
| | 11,700 |
| | 11,555 |
| | 11,402 |
|
| Industrial | 29,754 |
| | 28,517 |
| | 27,713 |
| | 27,025 |
| | 25,734 |
|
| Governmental | 790 |
| | 794 |
| | 756 |
| | 732 |
| | 723 |
|
| Total retail | 55,243 |
| | 54,599 |
| | 54,568 |
| | 53,727 |
| | 51,885 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 4,793 |
| | 7,345 |
| | 7,500 |
| | 6,240 |
| | 5,168 |
|
| Non-associated companies | 1,711 |
| | 1,690 |
| | 770 |
| | 1,051 |
| | 979 |
|
| Total | 61,747 |
| | 63,634 |
| | 62,838 |
| | 61,018 |
| | 58,032 |
|
| | | | | | | | | | |
ENTERGY MISSISSIPPI, INC.LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2023 Compared to 2022
Net Income
2017 Compared to 2016
Net income increased $0.8$417.5 million primarily due to the net effects of Entergy Louisiana’s storm cost securitization in March 2023, including a $133.4 million reduction in income tax expense, partially offset by a $103.4 million ($76.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding; a $179.1 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $38 million regulatory charge ($27.8 million net-of-tax) to reflect credits expected to be provided to customers; the reversal of a $105.6 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act, recorded in fourth quarter 2023, as part of the settlement of Entergy Louisiana’s test year 2017 formula rate plan filing; higher retail electric price; higher other income,income; lower other operation and maintenance expenses,expenses; and lower interesthigher volume/weather. The net income increase was partially offset by the net effects of Entergy Louisiana’s storm cost securitization in May 2022, including a $290 million reduction in income tax expense, substantiallypartially offset by a $224.4 million ($165.4 million net-of-tax) regulatory charge to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, and higher depreciation and amortization expensesexpenses. See Note 2 to the financial statements for further discussion of the storm cost securitizations and a higher effective income tax rate. the formula rate plan global settlement. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.
2016 Compared to 2015Operating Revenues
Net income increased $16.5 million primarily due to lower other operation and maintenance expenses, higher net revenues, and a lower effective income tax rate, partially offset by higher depreciation and amortization expenses.
Net Revenue
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenueoperating revenues comparing 20172023 to 2016.
| | | | | |
| Amount |
| | | (In Millions) |
| 2022 operating revenues | Amount$6,338.8 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (In Millions)(1,368.1) | |
| Storm restoration carrying costs | (6.9) | |
2016 net revenueReturn of unprotected excess accumulated deferred income taxes to customers |
24.6 | | $705.4
|
| Volume/weather | (18.240.8 | | )
| Retail electric price | 13.5118.6 | |
Other2023 operating revenues | 2.4$5,147.8 | |
2017 net revenue |
| $703.1 |
|
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.
Storm restoration carrying costs represent the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Hurricane Ida restoration costs in May 2022 and the equity component of storm restoration carrying costs recognized as part of the securitization of Hurricane Ida restoration costs in March 2023. See Note 2 to the financial statements for discussion of the storm cost securitizations.
The return of unprotected excess accumulated deferred income taxes to customers resulted from the return of unprotected excess accumulated deferred income taxes through changes in the formula rate plan effective May 2018 in response to the enactment of the Tax Cuts and Jobs Act. In 2022, $24.6 million was returned to customers through reductions in operating revenues. There was no return of unprotected excess accumulated deferred income taxes to customers in 2023. There was no effect on net income as the reductions in operating revenues were offset by reductions in income tax expense. See Note 2 to the financial statements for discussion of regulatory activity regarding the Tax Cuts and Jobs Act.
The volume/weather variance is primarily due to the effect of lessmore favorable weather on residential and commercial sales.
The retail electric price variance is primarily due to a $19.4 million net annual increaseincreases in rates, effective with the first billing cycle of July 2016, and an increaseformula rate plan revenues, including increases in the energy efficiency rider,distribution and transmission recovery mechanisms, effective with the first billing cycle of February 2017, each as approved by the MPSC. The increase was partially offset by decreased storm damage rider revenues due to resetting the storm damage provision to zero beginning with the November 2016 billing cycle. Entergy Mississippi resumed billing the storm damage rider effective with the September 2017 billing cycle.2022 and September 2023. See Note 2 to the financial statements for morefurther discussion of the formula rate plan proceedings.
Total electric energy sales for Entergy Louisiana for the years ended December 31, 2023 and the storm damage rider.2022 are as follows:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | | |
| Residential | 14,207 | | | 14,119 | | | 1 | |
| Commercial | 11,074 | | | 10,927 | | | 1 | |
| Industrial | 31,599 | | | 31,666 | | | — | |
| Governmental | 801 | | | 820 | | | (2) | |
| Total retail | 57,681 | | | 57,532 | | | — | |
| Sales for resale: | | | | | |
| Associated companies | 4,406 | | | 5,416 | | | (19) | |
| Non-associated companies | 1,534 | | | 3,423 | | | (55) | |
| Total | 63,621 | | | 66,371 | | | (4) | |
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
2015 net revenue |
| $696.3 |
|
Retail electric price | 12.9 |
|
Volume/weather | 4.7 |
|
Net wholesale revenue | (2.4 | ) |
Reserve equalization | (2.8 | ) |
Other | (3.3 | ) |
2016 net revenue |
| $705.4 |
|
The retail electric price variance is primarily due to a $19.4 million net annual increase in revenues, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider. See Note 219 to the financial statements for moreadditional discussion of the formula rate plan and the storm damage rider.Entergy Louisiana’s operating revenues.
The volume/weather variance is primarily due to an increase of 153 GWh, or 1%, in billed electricity usage, including an increase in industrial usage, partially offset by the effect of less favorable weather on residential and commercial sales. The increase in industrial usage is primarily due to expansion projects in the pulp and paper industry, increased demand for existing customers, primarily in the metals industry, and new customers in the wood products industry.
The net wholesale revenue variance is primarily due to Entergy Mississippi’s exit from the System Agreement in November 2015.
The reserve equalization revenue variance is primarily due to the absence of reserve equalization revenue as compared to the same period in 2015 resulting from Entergy Mississippi’s exit from the System Agreement in November 2015.
Other Income Statement Variances
2017 Compared to 2016
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $12 million in fossil-fueled generation expenses primarily due to lower long-term service agreement costs and a lower scope of work done during plant outages in 2017 as compared to the same period in 2016; and
a decrease of $3.6 million in storm damage provisions. See Note 2 to the financial statements for a discussion on storm cost recovery.
The decrease was partially offset by an increase of $4.8 million in energy efficiency costs and an increase of $2.7$27.9 million in compensation and benefits costs primarily due to lower health and welfare costs, including higher incentive-basedprescription drug rebates in second quarter 2023, a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount rates used to value the benefits liabilities, and a revision to estimated incentive compensation accrualsexpense in 2017first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
•a decrease of $25.1 million in transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs;
•a decrease of $12.3 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to the prior year.
2022;
Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•a decrease of $8.2 million in nuclear generation expenses primarily due to a lower scope of work performed in 2023 as compared to 2022, lower nuclear labor costs, and lower costs associated with materials and supplies in 2023 as compared to 2022; and
•a decrease of $7.2 million in customer service center support costs primarily due to lower contract costs.
The decrease was partially offset by:
•an increase of $15.9 million in contract costs related to operational performance, customer service, and organizational health initiatives;
•an increase of $6.1 million in insurance expenses primarily due to lower nuclear insurance refunds received in 2023; and
•several individually insignificant items.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other regulatory charges (credits) - net includes:
•a regulatory charge of $103.4 million, recorded in first quarter 2023, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the March 2023 storm cost securitization;
•a regulatory charge of $224.4 million, recorded in second quarter 2022, to reflect Entergy Louisiana’s obligation to provide credits to its customers as described in an LPSC ancillary order issued in the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida securitization regulatory proceeding. See Note 2 to the financial statements for discussion of the May 2022 storm cost securitization; and
•a regulatory charge of $38 million, recorded in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.
In addition, Entergy Louisiana records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.
Other income increased primarily due to:
•an increase of $113 million in affiliated dividend income from affiliated preferred membership interests related to interest incomestorm cost securitizations;
•a $31.6 million charge, recorded in connection withsecond quarter 2022, for the opportunity sales proceeding,LURC’s 1% beneficial interest incomein the storm trust I established as part of the Hurricane Laura, Hurricane Delta, Hurricane Zeta, Winter Storm Uri, and Hurricane Ida May 2022 storm cost securitization as compared to a $14.6 million charge, recorded onin first quarter 2023, for the deferred fuel balance,LURC’s 1% beneficial interest in the storm trust II established as part of the Hurricane Ida March 2023 storm cost securitization. See Note 2 to the financial statements for discussion of the storm cost securitizations;
•changes in decommissioning trust fund activity, including portfolio rebalancing of certain decommissioning trust funds in 2022; and
•an increase in the allowance for equity funds used during construction due to higher construction work in progress in 20172023.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by:
•a decrease of $20.6 million in the amount of storm restoration carrying costs recognized in 2023 as compared to 2016. 2022, primarily related to Hurricane Ida. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding.storm cost securitizations; and
Interest expense decreased primarily due•lower interest income from carrying costs related to the refinancing at lower interest rates of certain first mortgage bonds in 2016 and the retirement, at maturity, of $125 million of 3.25% Series first mortgage bonds in June 2016. See Note 5 to the financial statements for details of long-term debt.deferred fuel balance.
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
a decrease of $9.4 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2016 as compared to the same period in 2015;
a decrease of $6.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
a decrease of $2 million due to lower write-offs of uncollectible customer accounts in 2016;
a decrease of $2 million in energy efficiency costs; and
several individually insignificant items.
The decrease was partially offset by an increase of $7.1 million in storm damage provisions and an increase of $6 million in distribution expenses primarily due to higher vegetation maintenance. See Note 2 to the financial statements for a discussion of storm cost recovery.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Income Taxes
The effective income tax rates were (19.3%) for 2017, 2016,2023 and 2015 were 40.2%, 36.9%, and 40.0%, respectively.(23.5%) for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35%21% to the effective income tax rates.rates and for additional discussion regarding income taxes.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Planned Sale of Gas Distribution Business
See the “Planned Sale of Gas Distribution Businesses” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cutspurchase and Jobs Act, the federal income tax legislation enacted in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accountingsale agreement for the Act, and Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators to the Act.sale of Entergy Louisiana’s gas distribution business.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2017, 2016,2023, 2022, and 20152021 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $56,613 | | | $18,573 | | | $728,020 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 2,032,120 | | | 1,177,508 | | | 1,052,526 | |
| Investing activities | (3,039,456) | | | (4,707,711) | | | (3,700,199) | |
| Financing activities | 953,495 | | | 3,568,243 | | | 1,938,226 | |
| Net increase (decrease) in cash and cash equivalents | (53,841) | | | 38,040 | | | (709,447) | |
| | | | | |
| Cash and cash equivalents at end of period | $2,772 | | | $56,613 | | | $18,573 | |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $76,834 |
| |
| $145,605 |
| |
| $61,633 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 226,585 |
| | 212,280 |
| | 372,279 |
|
| Investing activities | (417,226 | ) | | (289,444 | ) | | (245,127 | ) |
| Financing activities | 119,903 |
| | 8,393 |
| | (43,180 | ) |
| Net increase (decrease) in cash and cash equivalents | (70,738 | ) | | (68,771 | ) | | 83,972 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $6,096 |
| |
| $76,834 |
| |
| $145,605 |
|
Operating Activities
Net cash flow provided by operating activities increased $14.3$854.6 million in 20172023 primarily due to:
•a decrease of $236.7 million in storm spending primarily due to Hurricane Ida restoration efforts in 2022;
•an increase of $42.4 million in interest received primarily due to shorter-term financing interest earnings and interest on storm reserve escrow accounts. See Note 2 to the financial statements for a discussion of shorter-term financing interest earnings;
•the refund of $27.8 million received from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See Note 2 to the financial statements for further discussion of the refund and the related proceedings;
•a decrease of $9.1 million in pension contributions in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
•lower fuel costs and the timing of recovery of fuel and purchased power costs in 2017 as compared to 2016 and an increase of $12.6 million in income tax refunds in 2017 as compared to 2016. Entergy Mississippi had income tax refunds in 2017 and 2016 in accordance with an intercompany income tax allocation agreement. The 2017 income tax refunds were primarily duecosts. See Note 2 to the utilizationfinancial statements for a discussion of Entergy Mississippi’s federal net operating lossesfuel and state income tax refunds resulting from purchased power cost recovery; and
•the carrybacktiming of net operating losses. payments to vendors.
The increase was partially offset by the timinglower collections from customers and an increase of payments to vendors.$14.4 million in interest paid.
Investing Activities
Net cash flow provided by operatingused in investing activities decreased $160$1,668.3 million in 20162023 primarily due to:
•an increase in investment in affiliates in 2022 due to the timing$3,163.6 million purchase by the storm trust I of recovery of fuel and purchased power costs in 2016 as compared to the same period in 2015 and $15.3 million in insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013. The decrease waspreferred membership interests issued by an Entergy affiliate, partially offset by income tax refundsthe $1,390.6 million redemption of $12.5 million in 2016 compared to income tax payments of $61.3 million in 2015. Entergy Mississippi had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 were primarily due to the results of operations and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit.preferred membership interests. See Note 32 to the financial statements for a discussion of the income tax audits.May 2022 storm cost securitization;
Investing Activities
Net cash flow used in investing activities increased $127.8•a decrease of $727 million in 2017distribution construction expenditures primarily due to:to lower capital expenditures for storm restoration in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
an increase•a decrease of $48.4$265.4 million in transmission construction expenditures primarily due to lower capital expenditures for storm restoration in 2023 and decreased spending on various transmission projects in 2023. The decrease in storm restoration expenditures is primarily due to Hurricane Ida restoration efforts in 2022;
•$125 million of redemptions in 2023 of preferred membership interests held by the storm trust I, as part of periodic redemptions that are expected to occur, subject to certain conditions, for the preferred membership interests that were issued in connection with the May 2022 storm cost securitization. See Note 2 to the financial statements for a higher scopediscussion of work performedthe May 2022 storm cost securitization and the storm trust I’s investment in 2017preferred membership interests; and
•net receipts from storm reserve escrow accounts of $49.6 million in 2023 as compared to 2016;
an increasenet payments to storm reserve escrow accounts of $39.2$293.4 million in fossil-fueled generation construction expenditures primarily due to a higher scope of work performed in 2017 as compared to 2016; and2022.
an increase of $30.2 million in distribution construction expenditures primarily due to
The decrease was partially offset by:
•an increase in investment in affiliates in 2023 due to the $1,457.7 million purchase by the storm spendingtrust II of preferred membership interests issued by an Entergy affiliate. See Note 2 to the financial statements for a discussion of the March 2023 storm cost securitization and the storm trust II’s investment in 2017 as compared to 2016 and increased spending on digital technology improvements within the customer contact centers.
preferred membership interests;
Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Net cash flow used in investing activities increased $44.3 million in 2016 primarily due to:
•an increase of $72.4$110.2 million in transmissionnuclear construction expenditures primarily due to a higher scope of work performedincreased spending on various nuclear projects in 2016 as compared to 2015;2023;
insurance proceeds of $12.9 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013;
•an increase of $11.4$47.5 million as a result of fluctuations in distribution construction expenditures primarilynuclear fuel activity due to a higher scopevariations from year to year in the timing and pricing of non-storm related work performed in 2016 as compared to 2015;fuel reload requirements, materials and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
an increase of $10.1 million due to various information technology projects and upgrades.
The increase was partially offset by a decrease of $20.1 million in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to 2015 and •money pool activity.
Decreases in Entergy Mississippi’s receivableLouisiana’s receivables from the money pool are a source of cash flow, and Entergy Mississippi’sLouisiana’s receivable from the money pool decreased by $15.3$14.5 million in 2016 compared to increasing by $25.3 million in 2015.2022. The money pool is an inter-companyintercompany cash management program that makes possible intercompany borrowing arrangementand lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Utility subsidiaries’ need forRegistrant Subsidiaries’ dependence on external short-term borrowings.
Financing Activities
Net cash flow provided by financing activities increased $111.5decreased $2,614.7 million in 20172023 primarily due to:
•proceeds from securitization of $1.5 billion received by the storm trust II in 2023 as compared to proceeds from securitization of $3.2 billion received by the issuancestorm trust I in 2022;
•the repayment, at maturity, of $150$665 million of 3.25%0.62% Series first mortgage bonds in November 20172023;
•the issuance of $500 million of 4.75% Series mortgage bonds in August 2022;
•the repayment, at maturity, of $325 million of 4.05% Series mortgage bonds in September 2023;
•the repayment, prior to maturity, of $300 million of 5.59% Series mortgage bonds in December 2023;
•an increase of $36.8 million in common equity distributions paid in 2023 in order to maintain Entergy Louisiana’s capital structure;
•the repayment, at maturity, of $20 million of 3.22% Series I notes by the Entergy Louisiana Waterford variable interest entity in December 2023; and
•money pool activity.
The decrease was partially offset by:
•a capital contribution of approximately $1.5 billion in 2023 as compared to a capital contribution of approximately $1 billion in 2022, both received indirectly from Entergy Corporation and related to the March 2023 storm cost securitization and the redemptionMay 2022 storm cost securitization, respectively;
•the repayment, prior to maturity, of $30$435 million, a portion of the outstanding principal, of 0.62% Series mortgage bonds in May 2022;
•the repayment, at maturity, of $200 million of 6.25%3.3% Series preferred stockmortgage bonds in 2016, partially offsetDecember 2022;
•the issuance of $70 million of 5.94% Series J notes by the net issuance of $61.4 million of long-term debtEntergy Louisiana Waterford variable interest entity in 2016.September 2023; and
Entergy Mississippi’s financing activities provided $8.4 million of cash in 2016 compared to using $43.2 million in 2015 primarily due to the net issuance of $61.4 million of long-term debt in 2016 and •a decrease of $16$25 million in common stock dividends paid2023 in 2016, partially offsetnet repayments on Entergy Louisiana’s revolving credit facility.
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 $69.9 million in 2023 compared to increasing by the redemption of $30$226.1 million of 6.25% Series preferred stock. The decrease in dividends paid was primarily because of lower operating cash flows and higher capital expenditures, each discussed above.2022.
See Note 5 to the financial statements for details onof long-term debt. See Note 2 to the financial statements for discussion of the storm cost securitizations.
2022 Compared to 2021
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
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Capital Structure
Entergy Mississippi’s capitalizationLouisiana’s debt to capital ratio is balanced between equity and debt, as shown in the following table. The increasedecrease in the debt to capital ratio for Entergy MississippiLouisiana is primarily due to the issuance$1.5 billion capital contribution received indirectly from Entergy Corporation in March 2023 and the net retirement of long-term debt in 2017.2023.
| | | | | | | | | | | |
| | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 44.9 | % | | 53.0 | % |
| | | |
| | | |
| Effect of subtracting cash | 0.0 | % | | (0.1 | %) |
| Net debt to net capital (non-GAAP) | 44.9 | % | | 52.9 | % |
|
| | | | | |
| | December 31,
2017 | | December 31,
2016 |
| Debt to capital | 51.5 | % | | 50.2 | % |
| Effect of subtracting cash | (0.2 | %) | | (1.8 | %) |
| Net debt to net capital | 51.3 | % | | 48.4 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, capitalfinance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy MississippiLouisiana 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’sLouisiana’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy MississippiLouisiana also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
and creditors in evaluating Entergy Mississippi’sLouisiana’s financial condition because net debt indicates Entergy Mississippi’sLouisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy MississippiLouisiana 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,distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy MississippiLouisiana may issue incremental debt or reduce dividends,distributions, or both, to maintain its targeted 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 dividends,reduced distributions, Entergy MississippiLouisiana may receive equity contributions to maintain the targetedits capital structure.
Uses of Capital
Entergy MississippiLouisiana requires capital resources for:
•construction and other capital investments;
•debt and preferred stock maturities or retirements;
•working capital purposes, including the financing of fuel and purchased power costs; and
dividend•distribution and interest payments.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Mississippi’sLouisiana’s planned construction and other capital investments.
| | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $435 | | | $805 | | | $780 | |
| Transmission | 520 | | | 775 | | | 1,220 | |
| Distribution | 775 | | | 790 | | | 755 | |
| Utility Support | 100 | | | 95 | | | 95 | |
| Total | $1,830 | | | $2,465 | | | $2,850 | |
|
| | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $55 |
| |
| $45 |
| |
| $260 |
|
| Transmission | 145 |
| | 100 |
| | 105 |
|
| Distribution | 125 |
| | 140 |
| | 130 |
|
| Utility Support | 70 |
| | 50 |
| | 35 |
|
| Total |
| $395 |
| |
| $335 |
| |
| $530 |
|
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019-2020 | | 2021-2022 | | After 2022 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $50 |
| |
| $234 |
| |
| $80 |
| |
| $1,784 |
| |
| $2,148 |
|
| Operating leases |
| $12 |
| |
| $19 |
| |
| $12 |
| |
| $6 |
| |
| $49 |
|
| Purchase obligations (b) |
| $280 |
| |
| $519 |
| |
| $490 |
| |
| $5,304 |
| |
| $6,593 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
(b) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Mississippi currently expects to contribute approximately $14.9 million to its qualified pension plans and approximately $110 thousand to other postretirement health care and life insurance plans in 2018, although the 2018 required pension contributions will be known with more certainty when the January 1, 2018 valuations are completed, which is expected by April 1, 2018 See “Critical Accounting Estimates
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
– Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy MississippiLouisiana includes amounts associated with specific investments such as transmissionin generation projects to enhance reliability, reduce congestion,modernize, decarbonize, and enable economic growth;diversify Entergy Louisiana’s portfolio; investments in River Bend and Waterford 3; distribution and Utility support spending to enhanceimprove reliability, resilience, and customer experience; transmission spending to improve reliability and improve service to customers, including investment to support advanced metering; resource planning, including potential generation projects; system improvements;resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term
Following are the amounts of Entergy Louisiana’s existing debt and preferred stock maturitieslease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027-2028 | | After 2028 |
| | (In Millions) |
| Long-term debt (a) | $1,719 | | | $659 | | | $983 | | | $1,419 | | | $9,635 | |
| Operating leases (b) | $17 | | | $14 | | | $11 | | | $13 | | | $4 | |
| Finance leases (b) | $6 | | | $5 | | | $4 | | | $6 | | | $3 | |
| | | | | | | | | |
(a)Long-term debt is discussed in NotesNote 5 and 6 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 $48.4 million to its qualified pension plans and approximately $15 million to its other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates- Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Louisiana has $128.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy 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 Mississippi dividendsUtility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings to Entergy Corporation at a percentage determined monthly. Provisions
2021 Solar Certification and the Geaux Green Option
In November 2021, Entergy Louisiana filed an application with the LPSC seeking certification of and approval for the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 megawatts (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consists of four resources that are expected to provide $242 million in net benefits to Entergy Louisiana’s customers. These resources, all of which would be constructed in Louisiana, include (i) the Vacherie Facility, a 150 megawatt resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 megawatt resource in Washington Parish; (iii) the St. Jacques Facility, a 150 megawatt resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 megawatt resource in Allen Parish. The St. Jacques Facility would be acquired through a build-own-transfer agreement; the remaining resources involve power purchase agreements. The Sunlight Road Facility and the Elizabeth Facility have estimated in service dates in 2024, and the Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025, but are now expected to be no sooner than 2027. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.
The proposed Rider GGO is a voluntary rate schedule that will enhance Entergy Louisiana’s ability to help customers meet their sustainability goals by allowing customers to align some or all of their electricity requirements with renewable energy from the resources. Because subscription fees from Rider GGO participants are expected to help offset the cost of the resources, the design of Rider GGO also preserves the benefits of the 2021 Solar Portfolio for non-participants by providing them with the reliability and capacity benefits of locally-sited solar generation at a discounted price.
In March 2022 direct testimony from Walmart, the Louisiana Energy Users Group (LEUG), and the LPSC staff was filed. Each party recommended that the LPSC approve the resources proposed in Entergy Mississippi’s articlesLouisiana’s application, and the LPSC staff witness indicated that the process through which Entergy Louisiana solicited or obtained the proposals for the resources complied with applicable LPSC orders. The LPSC staff and LEUG’s witnesses made recommendations to modify the proposed Rider GGO and Entergy Louisiana’s proposed rate relief. In April 2022 the LPSC staff and LEUG filed cross-answering testimony concerning each other’s proposed modifications to Rider GGO and the proposed rate recovery. Entergy Louisiana filed rebuttal testimony in June 2022. In August 2022 the parties reached a settlement certifying the 2021 Solar Portfolio and approving implementation of incorporation relatingRider GGO. In September 2022 the LPSC approved the settlement. Following the LPSC approval, the St. James Parish council issued a moratorium on new land use permits for solar facilities until the later of March 2023 or the completion of an environmental and economic impact study. In November 2023, St. James Parish lifted the moratorium and adopted an ordinance modifying the parish’s land use plan to preferred stock restrictestablish solar as an approved land use and defining corresponding solar regulations. Entergy Louisiana is in discussions with the counterparties to the Vacherie and St. Jacques facilities regarding amendments to the respective agreements to address the impact of the St. James Parish ordinance, and the facilities are expected to reach commercial operation no sooner than 2027, depending upon agreement by the parties on the terms of the amendments. In September 2023, Entergy Louisiana reported to the LPSC that it also entered into amended agreements related to the Sunlight Road and Elizabeth facilities. Both facilities are still expected to achieve commercial operation in 2024.
2022 Solar Portfolio and Expansion of the Geaux Green Option
In February 2023, Entergy Louisiana filed an application with the LPSC seeking certification of the Iberville/Coastal Prairie facility, which will provide 175 MW of capacity through a PPA with a third party, and the Sterlington facility, a 49 MW self-build project located near the deactivated Sterlington power plant (the 2022 Solar Portfolio). Entergy Louisiana is seeking to include these resources within the portfolio supporting the Rider GGO
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
rate schedule to help fulfill customer interest in access to renewable energy. Entergy Louisiana has requested the costs of these facilities, as offset by Rider GGO revenues, be deemed eligible for recovery in accordance with the terms of the formula rate plan and fuel adjustment clause rate mechanisms that exist at the time the facilities are placed into service. In January 2024, the parties filed an uncontested stipulated settlement agreement on the key issues in the case, which stated that the 2022 Solar Portfolio should be constructed, found that Entergy Louisiana’s proposed cost recovery mechanisms were appropriate, and confirmed the resources’ eligibility for inclusion in Rider GGO. The settlement was approved by the LPSC in January 2024. The Sterlington facility is expected to achieve commercial operation in January 2026.
Alternative RFP and Certification
In March 2023, Entergy Louisiana made the first phase of a bifurcated filing to seek approval from the LPSC for an alternative to the requests for proposals (RFP) process that would enable the acquisition of up to 3 GW of solar resources on a faster timeline than the current RFP and certification process allows. The initial phase of the filing established the need for the acquisition of additional resources and the need for an alternative to the RFP process. The second phase of the filing, which contains the details of the proposal for the alternative competitive procurement process and the information necessary to support certification, was filed in May 2023. In addition to the acquisition of up to 3 GW of solar resources, the filing also seeks approval of a new renewable energy credits-based tariff, Rider Geaux ZERO. Several parties have intervened, and a procedural schedule was established in May 2023 with a hearing scheduled for March 2024. In October 2023 the LPSC staff and intervenors filed testimony, with the LPSC staff supporting the amount of retained earnings availablesolar resources to be acquired and the alternative RFP process. The LPSC staff also supported, subject to certain recommendations, the proposed framework for evaluation and certification of the payment of cash dividends or other distributions on its commonsolar resources by the LPSC and preferred stock.the proposed tariff.
Advanced Metering Infrastructure (AMI)System Resilience and Storm Hardening
In November 2016,December 2022, Entergy MississippiLouisiana filed an application with the LPSC seeking an order froma public interest finding regarding Phase I of Entergy Louisiana’s Future Ready resilience plan and approval of a rider mechanism to recover the MPSC grantingprogram’s costs. Phase I reflects the first five years of a certificateten-year resilience plan and includes investment of public convenienceapproximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and necessitytelecommunications improvement. In April 2023 a procedural schedule was established with a hearing scheduled for January 2024. The LPSC staff and finding that Entergy Mississippi’s deploymentcertain intervenors filed direct testimony in August, September, and October 2023. The LPSC staff filed cross-answering testimony in October 2023. The testimony largely supports implementation of AMI issome level of accelerated investment in resilience, but raises various issues related to the magnitude of the investment, the cost recovery mechanism applicable to the investment, and the ratemaking for the investment. In January 2024 the hearing in this matter was rescheduled to April 2024.
The LPSC had previously opened a formal rulemaking proceeding in December 2021 to investigate efforts to improve resilience of electric utility infrastructure. In April 2023 the LPSC staff issued a draft rule in the public interest. Entergy Mississippi proposedrulemaking proceeding related to replace existing metersa requirement to file a grid resilience plan. The procedural schedule entered in the rulemaking proceeding contemplated adoption of a final rule in October 2023, but this did not occur, and a new date has not been set. The LPSC also has pending rulemakings addressing issues related to pole viability and grid maintenance practices. In December 2023, in those rulemakings, the LPSC staff issued a report and recommendation proposing to impose significant new reporting and compliance obligations related to jurisdictional utilities’ distribution and transmission operations, including new obligations related to grid hardening plans, pole inspections, pole replacement, vegetation management, storm restoration plans, new reliability metrics, software for handling customer complaints and complaint resolution, required use of drone technology, and new penalties and incentives for reliability performance and for compliance with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing included an estimate of implementation costs for AMI of $132 million. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15-year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value, approximately $56 million at December 31, 2015, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters,obligations. In February 2024, Entergy Louisiana and other parties filed comments on the three-year deploymentLPSC staff’s report.
Entergy Mississippi proposed to include the AMI deployment costsLouisiana, LLC and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable. In May 2017 the Mississippi Public Utilities StaffSubsidiaries
Management’s Financial Discussion and Entergy Mississippi entered into and filed a joint stipulation supporting Entergy Mississippi’s filing, and the MPSC issued an order approving the filing without material changes, finding that Entergy Mississippi’s deployment of AMI is in the public interest and granting a certificate of public convenience and necessity. The MPSC order also confirmed that Entergy Mississippi shall continue to include in rate base the remaining book value of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates.Analysis
Sources of Capital
Entergy Mississippi’sLouisiana’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 stock issuances;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.
internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Entergy Mississippi may refinance, redeem, or otherwiseLouisiana expects to continue, when economically feasible, to retire higher-cost debt and preferred stock prior to maturity, to the extentreplace it with lower-cost debt if market conditions and interest and dividend rates are favorable.permit.
All debt and common and preferred stockmembership interest issuances by Entergy MississippiLouisiana require prior regulatory approval. Preferred stock and debtDebt issuances are also subject to issuance tests set forth in its corporate charter, bond indenture,indentures and other agreements. Entergy MississippiLouisiana has sufficient capacity under these tests to meet its foreseeable capital needs.needs for the next twelve months and beyond.
Entergy Mississippi’sLouisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | | 2020 |
| (In Thousands) |
| ($156,166) | | ($226,114) | | $14,539 | | $13,426 |
|
| | | | | | |
| 2017 | | 2016 | | 2015 | | 2014 |
| (In Thousands) |
| $1,633 | | $10,595 | | $25,930 | | $644 |
See Note 4 to the financial statements for a description of the money pool.
Entergy MississippiLouisiana has four separatea credit facilitiesfacility in the aggregate amount of $102.5$350 million scheduled to expire May 2018. Noin June 2028. 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, 2023, there were no cash borrowings wereand no letters of credit outstanding under the credit facilities as of December 31, 2017.facility. In addition, Entergy MississippiLouisiana 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, 2017, a $15.32023, $17.1 million letterin letters of credit waswere outstanding under Entergy Mississippi’sLouisiana’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 2025. As of December 31, 2023, $46.6 million in loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. As of December 31, 2023, $29.5 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 MississippiLouisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana obtained authorizations from the FERC through October 2019April 2025 for the following:
•short-term borrowings not to exceed an aggregate amount of $175$450 million at any time outstanding and outstanding;
•long-term borrowings and security issuances. issuances; and
•borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Mississippi’sLouisiana’s short-term borrowing limits.
Hurricane Ida
As discussed in Note 2 to the financial statements, in August 2020 and October 2020, Hurricane Laura, Hurricane Delta, and Hurricane Zeta caused significant damage to portions of Entergy Louisiana’s service area. In February 2021 two winter storms (collectively, Winter Storm Uri) brought freezing rain and ice to Louisiana. 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 April 2022, Entergy Louisiana filed an application with the LPSC relating to Hurricane Ida restoration costs. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Ida were estimated to be approximately $2.54 billion, including approximately $1.96 billion in capital costs and approximately $586 million in non-capital costs. Including carrying costs of $57 million through December 2022, Entergy Louisiana was seeking an LPSC determination that $2.60 billion was prudently incurred and, therefore, eligible for recovery from customers. As part of this filing, Entergy Louisiana also was seeking an LPSC determination that an additional $32 million in costs associated with the restoration of Entergy Louisiana’s electric facilities damaged by Hurricane Laura, Hurricane Delta, and Hurricane Zeta as well as Winter Storm Uri was prudently incurred. This amount was exclusive of the requested $3 million in carrying costs through December 2022. In total, Entergy Louisiana was requesting an LPSC determination that $2.64 billion was prudently incurred and, therefore, eligible for recovery from customers. As discussed in Note 2 to the financial statements, in March 2022 the LPSC approved financing of a $1 billion storm escrow account from which funds were withdrawn to finance costs associated with Hurricane Ida restoration. In June 2022, Entergy Louisiana supplemented the application with a request regarding the financing and recovery of the recoverable storm restoration costs. Specifically, Entergy Louisiana requested approval to securitize its restoration costs pursuant to Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. In October 2022 the LPSC staff recommended a finding that the requested storm restoration costs of $2.64 billion, including associated carrying costs of $59.1 million, were prudently incurred and eligible for recovery from customers. The LPSC staff further recommended approval of Entergy Louisiana’s plans to securitize these costs, net of the $1 billion in funds withdrawn from the storm escrow account described above. The parties negotiated and executed an uncontested stipulated settlement which was filed with the LPSC in December 2022. The settlement agreement contains the following key terms: $2.57 billion of restoration costs from Hurricane Ida, Hurricane Laura, Hurricane Delta, Hurricane Zeta, and Winter Storm Uri were prudently incurred and eligible for recovery; carrying costs of $59.2 million were recoverable; and Entergy Louisiana was authorized to finance $1.657 billion utilizing the securitization process authorized by Act 55, as supplemented by Act 293. A procedural motion to consider the uncontested settlement at the December 2022 LPSC meeting did not pass and the settlement was not voted on. In January 2023 an ALJ with the LPSC conducted a settlement hearing to receive the uncontested settlement and supporting testimony into evidence and issued a report of proceedings, which allows the LPSC to consider the uncontested settlement without the procedural motion that did not pass in December. In January 2023, the LPSC approved the stipulated settlement subject to certain modifications. These modifications include the recognition of accumulated deferred income tax benefits related to damaged assets and system restoration costs as a reduction of the amount authorized to be financed utilizing the securitization process authorized by Act 55, as supplemented by Act 293, from $1.657 billion to $1.491 billion. These modifications did not affect the LPSC’s conclusion that all system restoration costs sought by Entergy Louisiana were reasonable and prudent. In February 2023 the Louisiana Bond Commission voted to authorize the Louisiana Local Government Facilities and Community Development Authority (LCDA) to issue the bonds authorized in the LPSC’s financing order.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In March 2023 the Hurricane Ida securitization financing closed, resulting in the issuance of approximately $1.491 billion principal amount of bonds by the LCDA and a remaining regulatory asset of $180 million to be recovered through the exclusion of the accumulated deferred income taxes related to damaged assets and system restoration costs from the determination of future rates. The securitization was authorized pursuant to the Louisiana Utilities Restoration Corporation Act, Part VIII of Chapter 9 of Title 45 of the Louisiana Revised Statutes, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021. The LCDA loaned the proceeds to the LURC. Pursuant to Act 293, the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the storm trust II).
Pursuant to Act 293, the net proceeds of the bonds were used by the storm trust II to purchase 14,576,757.48 Class B preferred, non-voting membership interest units (the preferred membership interests) issued by Entergy Finance Company, LLC, a majority owned indirect subsidiary of Entergy. Entergy Finance Company is required to make annual distributions (dividends) commencing on December 15, 2023 on the preferred membership interests issued to the storm trust II. These annual dividends received by the storm trust II will be distributed to Entergy Louisiana and the LURC, as beneficiaries of the storm trust II. Specifically, 1% of the annual dividends received by the storm trust II will be distributed to the LURC for the benefit of customers, and 99% will be distributed to Entergy Louisiana, net of storm trust expenses. The preferred membership interests have a stated annual cumulative cash dividend rate of 7.5% and a liquidation price of $100 per unit. The terms of the preferred membership interests include certain financial covenants to which Entergy Finance Company is subject. Semi-annual redemptions of the preferred membership interests, subject to certain conditions, are expected to occur over the next 15 years.
Entergy and Entergy Louisiana do not report the bonds issued by the LCDA on their balance sheets because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The system restoration charge is adjusted at least semi-annually to ensure that it is sufficient to service the bonds. Entergy Louisiana collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. Entergy Louisiana began collecting the system restoration charge effective with the first billing cycle of April 2023 and the system restoration charge is expected to remain in place for up to 15 years. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust II is required to liquidate Entergy Finance Company preferred membership interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial.
From the proceeds from the issuance of the preferred membership interests, Entergy Finance Company loaned approximately $1.5 billion to Entergy, which was indirectly contributed to Entergy Louisiana as a capital contribution.
As discussed in Note 3 to the financial statements, the securitization resulted in recognition of a net reduction of income tax expense of approximately $133 million, after taking into account a provision for uncertain tax positions, by Entergy Louisiana. Entergy’s recognition of reduced income tax expense was offset by other tax charges resulting in a net reduction of income tax expense of $129 million, after taking into account a provision for uncertain tax positions. In recognition of its obligations described in an LPSC ancillary order issued as part of the securitization regulatory proceeding, Entergy Louisiana recorded in first quarter 2023 a $103 million ($76 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect its obligation to provide credits to its customers.
As discussed in Note 6 and Note 17 to the financial statements, Entergy Louisiana consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is presented as noncontrolling interest in
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the financial statements. In first quarter 2023, Entergy Louisiana recorded a charge of $14.6 million in other income to reflect the LURC’s beneficial interest in the storm trust II.
Nelson Industrial Steam Company
Entergy Louisiana is a partner in the Nelson Industrial Steam Company (NISCO) partnership which owns two petroleum coke generating units. In April 2023 these generating units suspended operations in the MISO market, and Entergy Louisiana currently is working to wind up the NISCO partnership, which will ultimately result in ownership of the generating units transferring to Entergy Louisiana. In November 2023 the FERC issued an order providing Section 203 of the Federal Power Act approval for any subsequent transfer of the facilities to Entergy Louisiana. Entergy Louisiana is evaluating the effect of the transaction on its results of operations, cash flows, and financial condition, but at this time does not expect the effect to be material.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy MississippiLouisiana charges for electricityits services significantly influence its financial position, results of operations, and liquidity. Entergy MississippiLouisiana is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC,LPSC, is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
Filings with the LPSC
2017 Formula Rate Plan Filing
In March 2016,June 2018, Entergy Mississippi submittedLouisiana filed its formula rate plan 2016evaluation report for its 2017 calendar year operations. The 2017 test year filing showing Entergy Mississippi’s projectedevaluation 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 2016 calendar yeartax 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 be belowadjustments to the additional capacity and MISO cost recovery mechanisms of the formula rate plan, bandwidth. The filing showedand implementation of the transmission recovery mechanism. In August 2018, Entergy Louisiana filed a $32.6 millionsupplemental formula rate increase was necessaryplan evaluation report to reset Entergy Mississippi’s earned return on common equityreflect changes from the 2016 test year formula rate plan proceedings, a decrease to the specified pointtransmission recovery mechanism to reflect lower actual capital additions, and a decrease to evaluation period expenses to reflect the terms of adjustmenta new power sales agreement. Based on the August 2018 update, Entergy Louisiana recognized a total decrease in formula rate plan revenue of 9.96%, withinapproximately $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, bandwidth. In June 2016in September 2018 the MPSC approvedLPSC staff filed its report of objections/reservations and intervenors submitted their responses to Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase includes a $19.4 million increase through theLouisiana’s original formula rate plan resulting inevaluation report and supplemental compliance updates. In August 2021 the LPSC staff issued a return on common equity point of adjustment of 10.07%. The revenue increase also includes $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective withletter updating its objections/reservations for the July 2016 bills.
In March 2017 Entergy Mississippi submitted itstest year formula rate plan evaluation report. In its letter, the LPSC staff reiterated its original objections/reservations. The LPSC staff further reserved its rights for future proceedings and to dispute future proposed adjustments to the 2017 test year filing and 2016 look-back filing showing Entergy Mississippi’s earned return for the historical 2016 calendar year and projected earned return for the 2017 calendar year to be within the formula rate plan bandwidth, resulting in no change in rates. evaluation report. The LPSC staff withdrew all other objections/reservations.
In JuneNovember 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, Entergy Mississippi2018, and 2019 formula rate plan filings and resolved certain issues with respect to the Mississippi Public Utilities Staff entered into a stipulation that confirmed that Entergy2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.
Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2018 Formula Rate Plan Filing
Mississippi’s
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 returnsreturn on common equity of 10.61% leading to a base rider formula rate plan revenue decrease of $8.9 million. While base rider formula rate plan revenue decreased as a result of this filing, overall formula rate plan revenues increased by approximately $118.7 million. This outcome was primarily driven by a reduction to the credits previously flowed through the tax reform adjustment mechanism and an increase in the transmission recovery mechanism, partially offset by reductions in the additional capacity mechanism revenue requirements and extraordinary cost items. The filing was subject to review by the LPSC. Resulting rates were implemented in September 2019, subject to refund.
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 August 2021 the LPSC staff issued a letter updating its objections/reservations for both the 2016 look-back filing2018 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 were within the respective formula rate plan bandwidths.evaluation report. The LPSC staff withdrew all other objections/reservations.
Commercial operation at Lake Charles Power Station commenced in March 2020. In June 2017March 2020, Entergy Louisiana filed an update to its 2018 formula rate plan evaluation report to include the MPSC approved the stipulation, which resulted in no change in rates.
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 authorityestimated first-year revenue requirement of the MPSC.
Entergy Mississippi had a deferred fuel over-recovery balance of $58.3$108 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi should file a revised fuel factorassociated with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for anotherLake Charles Power Station. The resulting interim adjustment to rates became effective with the energy cost factor effectivefirst billing cycle of April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.2020.
In November 2016, Entergy Mississippi filed its annual redetermination2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the annual factorsettlement.
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 be applied underbase rider formula rate plan revenue is required. Although base rider formula rate plan revenue did not change as a result of this filing, overall formula rate plan revenues increased by approximately $103 million. This outcome is driven by the energyremoval 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 rider. The calculationmechanism 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 annual factor included2019 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 over-recoveryAugust 2020 filing, were implemented in September 2020, subject to refund. 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 disputed Entergy Louisiana’s exclusion of less than $2 million asapproximately $251 thousand of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also in January 2017 the MPSC certifiedinterest income allocated from Entergy Operations and Entergy Services to Entergy Louisiana to the Mississippi Legislatureextent that there are other adjustments that would move Entergy Louisiana out of the audit reports of its independent auditors for the fuel year ending September 30, 2016. In its order, the MPSC expresslyformula rate plan deadband. The LPSC staff reserved the right to reviewfurther contest the issue in future proceedings. The LPSC staff further reserved outstanding issues from the 2017 and determine the recoverability of any2018 formula rate plan evaluation reports and withdrew all purchased power expenditures made during fiscal year 2016. The MPSC hired independent auditors to conduct an annual operations audit and a financial audit. The independent auditors issued their audit reports in December 2017. The audit reports included several recommendations for action by Entergy Mississippi but did not recommend any cost disallowances. In January 2018 the MPSC certified the audit reports to the Mississippi Legislature. In November 2017 the Public Utilities Staff separately engaged a consultant to review the outage at the Grand Gulf Nuclear Station that began in 2016. The review is currently in progress.other remaining objections/reservations.
In November 2017, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an under-recovery of approximately $61.5 million as of September 30, 2017. Entergy Mississippi proposed a two-tiered energy cost factor designed to promote overall rate stability throughout 2018 particularly during the summer months. In January 2018 the MPSC approved the proposed energy cost factors effective for February 2018 bills.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District
Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.
Court issued
Request for Extension and Modification of Formula Rate Plan
In May 2020, Entergy Louisiana filed with the LPSC its application for authority to extend its formula rate plan. In its application, Entergy Louisiana sought to maintain a 9.8% return on equity, with a bandwidth of 60 basis points above and below the midpoint, with a first-year midpoint reset. The parties reached a settlement in April 2021 regarding Entergy Louisiana’s proposed formula rate plan extension. In May 2021 the LPSC approved the uncontested settlement. Key terms of the settlement include: a three year term (test years 2020, 2021, and 2022) covering a rate-effective period of September 2021 through August 2024; a 9.50% return on equity, with a smaller, 50 basis point deadband above and below (9.0%-10.0%); elimination of sharing if earnings are outside the deadband; a $63 million rate increase for test year 2020 (exclusive of riders); continuation of existing riders (transmission, additional capacity, etc.); addition of a distribution recovery mechanism permitting $225 million per year of distribution investment above a baseline level to be recovered dollar for dollar; modification of the tax mechanism to allow timely rate changes in the event the federal corporate income tax rate is changed from 21%; a cumulative rate increase limit of $70 million (exclusive of riders) for test years 2021 and 2022; and deferral of up to $7 million per year in 2021 and 2022 of expenditures on vegetation management for outside of right of way hazard trees.
2020 Formula Rate Plan Filing
In June 2021, Entergy Louisiana filed its formula rate plan evaluation report for its 2020 calendar year operations. The 2020 test year evaluation report produced an opinion denyingearned 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 Attorney General’s motionTax 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, remand, findingamong other things, the calculation of distribution recovery mechanism revenues. The effects of the changes to total formula rate plan revenue were different for each legacy company, primarily due to differences in the legacy companies’ capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $27 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $23.7 million. Subject to LPSC review, the resulting changes became effective for bills rendered during the first billing cycle of September 2021, subject to refund. Discovery commenced in the proceeding. In August 2021, Entergy Louisiana submitted an update to its evaluation report to account for various changes. Relative to the June 2021 filing, the total formula rate plan revenue increased by $14.2 million to an updated total of $64.9 million. Legacy Entergy Louisiana formula rate plan revenues increased by $32.8 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $32.1 million. The results of the 2020 test year evaluation report bandwidth calculation were unchanged as there was no change in the earned return on common equity of 8.45%. In September 2021 the LPSC staff filed a letter with a general statement of objections/reservations because it had not completed its review and indicated it would update the letter once its review was complete. Should the parties be unable to resolve any objections, those issues will be set for hearing, with recovery of the associated costs subject to refund.
In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2021 Formula Rate Plan Filing
In May 2022, Entergy Louisiana filed its formula rate plan evaluation report for its 2021 calendar year operations. The 2021 test year evaluation report produced an earned return on common equity of 8.33%, with a base formula rate plan revenue increase of $65.3 million. Other increases in formula rate plan revenue driven by reductions in Tax Cut and Jobs Act credits and additions to transmission and distribution plant in service reflected through the transmission recovery mechanism and distribution recovery mechanism are partly offset by an increase in net MISO revenues, leading to a net increase in formula rate plan revenue of $152.9 million. The effects of the changes to total formula rate plan revenue are different for each legacy company, primarily due to differences in the legacy companies’ capacity cost changes, including the effect of true-ups. Legacy Entergy Louisiana formula rate plan revenues increased by $86 million and legacy Entergy Gulf States Louisiana formula rate plan revenues increased by $66.9 million. In August 2022 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2020 formula rate plan filings, utilizing the extraordinary cost mechanism to address one-time changes such as state tax rate changes, and failing to include an adjustment for revenues not received as a result of Hurricane Ida. Subject to LPSC review, the resulting changes to formula rate plan revenues became effective for bills rendered during the first billing cycle of September 2022, subject to refund.
In November 2023 the LPSC approved a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement.
2022 Formula Rate Plan Filing
In May 2023, Entergy Louisiana filed its formula rate plan evaluation report for its 2022 calendar year operations. The 2022 test year evaluation report produced an earned return on common equity of 8.33%, requiring an approximately $70.7 million increase to base rider revenue. Due to a cap for the 2021 and 2022 test years, however, base rider formula rate plan revenues are only being increased by approximately $4.9 million, resulting in a revenue deficiency of approximately $65.9 million and providing for prospective return on common equity opportunity of approximately 8.38%. Other changes in formula rate plan revenue driven by increases in capacity costs, primarily legacy capacity costs, additions eligible for recovery through the transmission recovery mechanism and distribution recovery mechanism, and higher sales during the test period are offset by reductions in net MISO costs as well as credits for FERC-ordered refunds. Also included in the 2022 test year distribution recovery mechanism revenue requirement is a $6 million credit relating to the distribution recovery mechanism performance accountability standards and requirements. In total, the net increase in formula rate plan revenues, including base formula rate plan revenues inside the formula rate plan bandwidth and subject to the cap, as well as other formula rate plan revenues outside of the bandwidth, is $85.2 million. In August 2023 the LPSC staff filed a list of objections/reservations, including outstanding issues from the test years 2017-2021 formula rate plan filings, the calculation of certain refunds from System Energy, and certain calculations relating to the tax reform adjustment mechanism. Subject to LPSC review, the resulting net increase in formula rate plan revenues of $85.2 million became effective for bills rendered during the first billing cycle of September 2023, subject to refund.
2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request
In August 2023, Entergy Louisiana filed an application for approval of a regulatory blueprint necessary for it to strengthen the electric grid for the State of Louisiana, which contains a dual-path request to update rates through either: (1) extension of Entergy Louisiana’s current formula rate plan (with certain modifications) for three years (the Rate Mitigation Proposal), which is Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complies with Entergy Louisiana’s previous formula rate plan extension order requiring that for Entergy Louisiana to obtain another extension of its formula rate plan that included a rate reset, Entergy Louisiana would need to submit a full cost-of-
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Management’s Financial Discussion and Analysis
service/rate case. Entergy Louisiana’s filing supports the District Court has subject matter jurisdiction underneed to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms to facilitate investment in the Class Action Fairness Act.distribution, transmission, and generation functions.
The defendantRate Case path proposes a 2024-2026 test year formula rate plan with an initial revenue requirement increase of $430 million, net of $17 million of one-time credits, and a return on common equity of 10.5%. Depreciation rates would be updated for all asset classes. The Rate Mitigation Proposal proposes a 2023-2025 test year formula rate plan with an expected initial revenue requirement increase of $173 million, also net of $17 million of one-time credits, based on a 2023 formula rate plan test year, and a return on common equity of 10.0%. Depreciation rates would be updated only for nuclear assets and would be phased in over three years.
Under both paths, Entergy companies answeredLouisiana’s filing proposes removing the complaintcap on amounts allowed to be recovered through the distribution recovery mechanism and filedcontinuing the distribution recovery mechanism performance accountability targets, which tie Entergy Louisiana’s ability to fully recover its distribution recovery mechanism investments to its reliability performance. Entergy Louisiana’s filing also includes new customer-centric programs specifically focused on affordability, including reducing late fees and certain other fees assessed to customers, lowering additional facilities charge rates, providing eligible low-income seniors with monthly discounts on their electric bill, and adding new voluntary customer options to support new transportation electrification technologies. A status conference was held in October 2023 at which a counterclaimprocedural schedule was adopted that includes three technical conferences, the last of which is in March 2024, and a hearing date in August 2024.
Formula Rate Plan Global Settlement
In October 2023 the LPSC staff and Entergy Louisiana reached a global settlement which resolved all outstanding issues related to the 2017, 2018, and 2019 formula rate plan filings and resolved certain issues with respect to the 2020 and 2021 formula rate plan filings. The settlement was approved by the LPSC in November 2023. The settlement resulted in a one-time cost of service credit to customers of $5.8 million, allowed Entergy Louisiana to retain approximately $6.2 million of securitization over-collection as recovery of a regulatory asset associated with late fees related to the 2016 Baton Rouge flood, and resulted in Entergy Louisiana recording the reversal of a $105.6 million regulatory liability, associated with the Hurricane Isaac securitization, recognized in 2017 as a result of the Tax Cuts and Jobs Act. See Note 3 to the financial statements for relieffurther discussion of the reversal of the regulatory liability.
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 cost recovery
Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the Mississippi Public Utilities Actlevel 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 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 Federal Power Act.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
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Management’s Financial Discussion and Analysis
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, including both gas and electric utilities. At its June 2021 meeting, the LPSC approved the hiring of consultants to assist its staff in this review. In May 20092022 the defendantLPSC staff issued an audit report regarding Entergy companiesLouisiana’s fuel adjustment clause charges (for its electric operations) recommending no financial disallowances, but including several prospective recommendations. Responsive testimony was filed by one intervenor and the parties agreed to suspend any procedural schedule and move toward settlement discussions to close the matter. Also in May 2022 the LPSC staff issued an audit report regarding Entergy Louisiana’s purchased gas adjustment charges (for its gas operations) that did not propose any financial disallowances. The LPSC staff and Entergy Louisiana submitted a motion for judgmentjoint report on the pleadings asserting groundsaudit report and draft order to the LPSC concluding that Entergy Louisiana’s gas distribution operations and fuel costs were not significantly adversely affected by the February 2021 winter storms and the resulting increase in natural gas prices. The LPSC issued an order approving the joint report in October 2022.
In March 2021 the LPSC staff provided notice of federal preemption,an audit of Entergy Louisiana’s purchased gas adjustment clause filings covering the exclusive jurisdictionperiod January 2018 through December 2020. The audit included a review of the MPSC,reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for that period. In August 2023 the LPSC submitted its audit report and factual errorsfound that materially all costs recovered through the purchased gas adjustment filings were reasonable and eligible for recovery through the purchased gas adjustment clause. The LPSC approved the report in December 2023.
To mitigate high electric bills, primarily driven by high summer usage and elevated gas prices, Entergy Louisiana deferred approximately $225 million of fuel expense incurred in April, May, June, July, August, and September 2022 (as reflected on June, July, August, September, October, and November 2022 bills). These deferrals were included in the Attorney General’s complaint. In September 2012over/under calculation of the District Court heard oral argumentfuel adjustment clause, which is intended to recover the full amount of the costs included on Entergy’s motion for judgment on the pleadings.a rolling twelve-month basis.
In January 20142023 the U.S. Supreme Court issuedLPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings. The audit includes a decision in which it held that cases brought by attorneys general asreview of the sole plaintiff to enforce state laws were not considered “mass actions” underreasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day laterperiod from 2021 through 2022. Discovery is ongoing, and no audit report has been filed.
In January 2023 the Attorney General renewed his motion to remandLPSC 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 case back to state court, citingLouisiana’s fuel adjustment clause for the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction,period from 2020 through 2022. Discovery is ongoing, and the District Court held oral argument on the renewed motion to remand in February 2014. no audit report has been filed.
COVID-19 Orders
In April 20152020 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth CircuitLPSC issued an order denyingauthorizing utilities to record as a regulatory asset expenses incurred from the appeal,suspension of disconnections and collection of late fees imposed by LPSC orders associated with the Attorney General subsequentlyCOVID-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. In April 2023, Entergy Louisiana filed a petition for rehearingan application proposing to utilize approximately $1.6 billion in certain low interest debt to generate earnings to apply toward the reduction of the request for interlocutory appeal, which was also denied. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings,COVID-19 regulatory asset, as well as supplemental briefs regardingto conduct additional outside right-of-way vegetation management activities and fund the same. Those filingsminor storm reserve account. In that filing, Entergy Louisiana proposed to delay repayment of certain shorter-term first mortgage bonds that were madeissued to finance storm restoration costs until the costs could be securitized, and to invest the funds that otherwise would be used to repay those bonds in January 2016.the money pool to take advantage of the spread between prevailing interest rates on investments in the money pool and the interest rates on the bonds. The LPSC
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
approved Entergy Louisiana’s requested relief in June 2023. A subsequent filing will be required to permit the LPSC to review the COVID-19 regulatory asset. As of December 31, 2023, Entergy Louisiana had a regulatory asset of $47.8 million for costs associated with the COVID-19 pandemic and a regulatory liability of $36.8 million for the deferred earnings related to the approximately $1.6 billion in low interest debt.
Net Metering Rulemaking
In September 20162019 the Attorney General filedLPSC issued an order modifying its rules regarding net metering installations. Among other things, the rule provides for 2-channel billing for net metering with excess energy put to the grid being compensated at the utility’s avoided cost. However, the rule does provide that net meter installations in place as of December 31, 2019 will be subject to 1:1 net metering with excess energy put to the grid being compensated at the full retail rate for a mandamus petition withperiod of 15 years (through December 31, 2034), after which those installations will be subject to 2-channel billing. The rule also eliminates the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgmentexisting limit on the pleadings. The cumulative number of net meter installations.
Industrial and Commercial Customers
Entergy companies filed a motion seekingLouisiana’s large industrial and commercial customers continually explore ways to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowingreduce their energy costs. In particular, cogeneration is an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the caseoption 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 judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings. In June 2017 the District Court issued a case management order setting a trial date in November 2018. Discovery is currently in progress.and existing customers.
Storm Damage Provision
Entergy Mississippi has approval from the MPSC to collect a storm damage provision of $1.75 million per month. If Entergy Mississippi’s accumulated storm damage provision balance exceeds $15 million, the collection of the storm damage provision ceases until such time that the accumulated storm damage provision becomes less than $10 million. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with November 2016 bills. As of July 31, 2017, the balance in Entergy Mississippi’s accumulated storm damage provision was again less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with September 2017 bills.
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 generating plants and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the use, storage, and handling and disposal of high-level and low-level radioactive materials; the substantial financial requirements, both for capital investments and operational needs, including the financial requirements to address emerging issues related to equipment reliability, to position Entergy Louisiana’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 of insurance recoveries for losses in connection with nuclear plant operations and catastrophic events such as a nuclear accident. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3’s operating license expires in 2044 and River Bend’s operating license expires in 2045.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s
Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. Waterford 3 is currently in Column 1, and River Bend is currently in Column 2.
Nuclear Matters
In July 2023 the NRC placed River Bend in Column 2, effective April 2023, based on failure to inspect wiring associated with the high pressure core spray system. In August 2023 the NRC issued a finding and notice of violation related to a radiation monitor calibration issue at River Bend. In December 2023, River Bend successfully completed the inspection on the high pressure core spray system issue and in February 2024, River Bend successfully completed the supplemental inspection for the radiation monitor calibration issue involving radiation monitor calibrations. River Bend will remain in Column 2 pending receipt of the formal report on the inspection, which is expected in first quarter 2024.
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’sLouisiana’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 MississippiLouisiana 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’sLouisiana’s financial statements in conformity with generally accepted accounting principlesGAAP 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 thethese assumptions and measurements that could produce estimates that would have a material impacteffect on the presentation of Entergy Mississippi’sLouisiana’s financial position, or results of operations.operations, or cash flows.
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.
Unbilled Revenue
See “Unbilled Revenue” 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 unbilled revenue amounts.
Impairment of Long-lived Assets and Trust Fund Investments
See “Impairment of Long-lived Assets and Trust Fund Investments” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the impairment of long-lived assets.
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Qualified Pension and Other Postretirement Benefits
Entergy Mississippi’sLouisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impactedaffected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
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 2024 Qualified Pension Cost | | Impact on 2023 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,016 | | $28,165 |
| Rate of return on plan assets | | (0.25%) | | $2,739 | | $— |
| Rate of increase in compensation | | 0.25% | | $1,143 | | $6,017 |
|
| | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Qualified Pension Cost | | Impact on 2017 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $874 | |
| $13,479 |
|
| Rate of return on plan assets | | (0.25%) | | $867 | |
| $— |
|
| Rate of increase in compensation | | 0.25% | | $381 | |
| $1,848 |
|
The following chart reflects the sensitivity of postretirement benefitbenefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2024 Postretirement Benefits Cost | | Impact on 2023 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $324 | | $4,287 |
| Health care cost trend | | 0.25% | | $559 | | $2,905 |
|
| | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2018 Postretirement Benefit Cost | | Impact on 2017 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $184 | | $2,561 |
| Health care cost trend | | 0.25% | | $296 | | $2,024 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and FundingEmployer Contributions
Total qualified pension cost for Entergy MississippiLouisiana in 20172023 was $8.5 million.$69.5 million, including $40.4 million in settlement costs. Entergy MississippiLouisiana anticipates 20182024 qualified pension cost to be $10.8 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.8$10.7 million. Entergy MississippiLouisiana contributed $19.1$44.6 million to its qualified pension plans in 20172023 and estimates 2018 pension contributions will be approximately $14.9$48.4 million in 2024, although the 20182024 required pension contributions will be known with more certainty when the January 1, 20182024 valuations are completed, which is expected by April 1, 2018.2024.
Total postretirement health care and life insurance benefit incomecosts for Entergy MississippiLouisiana in 2017 was $12023 were $1.4 million. Entergy MississippiLouisiana expects 20182024 postretirement health care and life insurance benefit income of approximately $1.5 million. In 2016,$701 thousand. Entergy Mississippi refinedLouisiana contributed $20.5 million to its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $770 thousand. In 2017, Entergy Mississippi’s contributions (that is, contributions to the external trusts plus claims payments) were offset by trust claims reimbursements, resultingplans in a net reimbursement of $2 thousand. Entergy Mississippi2023 and estimates that 20182024 contributions will be approximately $110 thousand.$15 million.
Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Contingencies
Federal Healthcare Legislation
See “Qualified Pension and Other Postretirement Benefits -Federal Healthcare LegislationContingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
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 the “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 shareholdersmember and Board of Directors of
Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Mississippi, Inc.Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 20172023 and 2016,2022, the related consolidated statements of income, comprehensive income, cash flows, and changes in common equity (pages 370368 through 374 and applicable items in pages 5547 through 230)238), for each of the three years in the period ended December 31, 2017,2023, 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, 20172023 and 2016,2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Rate and Regulatory Matters — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Louisiana Public Service Commission (the “LPSC”), which has jurisdiction with respect to the rates of electric companies in Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the LPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the LPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery in future rates of incurred costs, and refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the LPSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the LPSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities 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 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 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 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 external information and compared to management’s recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected the Company’s filings with the LPSC and the FERC and orders issued, and considered the filings with the LPSC and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions.
•We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.
Securitization Financing — Storm Cost Recovery Filings with Retail Regulators — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
Hurricane Ida in 2021 caused significant damage to portions of the Company’s service area within the state of Louisiana. In January 2023, the LPSC issued a Financing Order authorizing financing of $1.491 billion of system restoration costs utilizing the securitization process authorized by Louisiana Act 55 financing, as supplemented by Act 293 of the Louisiana Legislature’s Regular Session of 2021 (“Act 55, as supplemented by Act 293”). In March 2023, the securitization financing closed, resulting in the issuance of $1.491 billion principal amount bonds by
Louisiana Local Government Environmental Facilities and Community Development Authority (“LCDA”), a political subdivision of the State of Louisiana. The LCDA loaned the proceeds to the Louisiana Utilities Restoration Corporation (“LURC”), and the LURC contributed the net bond proceeds to a State legislatively authorized and LURC-sponsored trust, Restoration Law Trust II (the “storm trust II”). The Company and the LURC each hold beneficial interests in the storm trust II.
The Company does not report the bonds issued by the LCDA on its balance sheet because the bonds are the obligation of the LCDA. The bonds are secured by system restoration property, which is the right granted by law to the LURC to collect a system restoration charge from customers. The Company collects the system restoration charge on behalf of the LURC and remits the collections to the bond indenture trustee. The Company does not report the collection of system restoration charges as revenue because the Company is merely acting as a billing and collection agent for the LCDA and the LURC. In the remote possibility that the system restoration charge, as well as any funds in the excess subaccount and funds in the debt service reserve account, are insufficient to service the bonds resulting in a payment default, the storm trust II is required to liquidate Entergy Finance Company preferred interests in an amount equal to what would be required to cure the default. The estimated value of this indirect guarantee is immaterial. The Company consolidates the storm trust II as a variable interest entity and the LURC’s 1% beneficial interest is shown as a noncontrolling interest in the financial statements.
We identified management’s conclusion that the bonds issued by the LCDA are the obligation of the LCDA as a critical audit matter due to the judgments made by management to support its conclusion. Auditing management’s judgments involved especially subjective judgment and specialized knowledge of accounting for securitization financing transactions.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the Act 55, as supplemented by Act 293, securitization financing included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the accounting impact of this securitization financing transaction, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.
•We evaluated the Company’s disclosures related to the impacts of the Act 55, as supplemented by Act 293, securitization financing, including the balances recorded.
•We read relevant regulatory and financing orders issued by the LPSC for the Company, the LURC, and the LCDA, and evaluated the external information to compare to management’s conclusions.
•We obtained an analysis from management and support from the Company’s internal and external legal counsel regarding the legal status of the bonds issued by the LCDA and the system restoration property granted to the LURC to assess management’s assertion that the bonds issued by the LCDA are the obligation of the LCDA.
•With the assistance of professionals in our firm having expertise and experience in addressing the accounting for securitization financing transactions by regulated utilities, we evaluated the Company’s conclusion, including the conclusion that the bonds issued by the LCDA are the obligation of the LCDA.
Uncertain Tax Positions — Entergy Louisiana, LLC and Subsidiaries — Refer to Note 3 to the financial statements
Critical Audit Matter Description
The Company accounts for uncertain income tax positions under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than fifty percent likely of being realized upon settlement. The Company has uncertain tax positions which require management to make judgments and assumptions to determine whether available information supports the assertion that the recognition threshold is met, particularly related to the technical merits and facts and circumstances of each position, as well as the probability of different potential outcomes. These uncertain tax positions could be significantly affected by audits by taxing authorities of the tax positions and changes to relevant tax law. There is an uncertain tax position related to the March 2023 securitization financing that provided for a tax benefit in the first quarter of 2023 of approximately $129 million.
Given the judgments made by management, we identified management’s conclusion that the securitization uncertain tax position met the more-likely-than-not recognition threshold as a critical audit matter. Auditing management’s
judgments regarding this uncertain tax position involved specialized knowledge of uncertain tax positions and auditor judgment to evaluate the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the securitization uncertain tax position included the following, among others:
•We tested the effectiveness of controls related to the securitization uncertain tax position, including those over the recognition and measurement of the income tax benefit.
•We evaluated the Company’s disclosures, and the balances recorded, related to the securitization uncertain tax position.
•We evaluated the methods and assumptions used by management to estimate the uncertain tax position by testing the underlying data that served as the basis for the uncertain tax position.
•With the assistance of our income tax specialists, we tested the technical merits of the securitization uncertain tax position and management’s key estimates and judgments made by:
•Assessing the technical merits of the uncertain tax position by comparing to similar cases filed with the Internal Revenue Service.
•Obtaining an opinion from the Company’s external legal counsel regarding certain federal income tax consequences related to the Act 55, as supplemented by Act 293, securitization financing and evaluating whether the analysis was consistent with our interpretation of the relevant laws and circumstances.
•Considering the impact of changes or settlements in the tax environment on management’s methods and assumptions used to estimate the uncertain tax position.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 26, 201823, 2024
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $5,073,239 | | | $6,246,933 | | | $4,994,459 | |
| Natural gas | | 74,531 | | | 91,835 | | | 73,989 | |
| TOTAL | | 5,147,770 | | | 6,338,768 | | | 5,068,448 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 1,080,485 | | | 2,002,456 | | | 1,302,291 | |
| Purchased power | | 654,721 | | | 1,076,715 | | | 768,546 | |
| Nuclear refueling outage expenses | | 63,429 | | | 59,698 | | | 49,373 | |
| Other operation and maintenance | | 1,097,233 | | | 1,139,605 | | | 1,034,427 | |
| Decommissioning | | 75,962 | | | 72,122 | | | 68,575 | |
| Taxes other than income taxes | | 245,191 | | | 241,908 | | | 224,079 | |
| Depreciation and amortization | | 726,389 | | | 695,204 | | | 656,132 | |
| Other regulatory charges (credits) - net | | 41,209 | | | 148,871 | | | 38,245 | |
| TOTAL | | 3,984,619 | | | 5,436,579 | | | 4,141,668 | |
| | | | | | |
| OPERATING INCOME | | 1,163,151 | | | 902,189 | | | 926,780 | |
| | | | | | |
| OTHER INCOME | | | | | | |
| Allowance for equity funds used during construction | | 32,160 | | | 26,252 | | | 28,648 | |
| Interest and investment income (loss) | | 90,316 | | | (69,144) | | | 154,606 | |
| Interest and investment income - affiliated | | 303,233 | | | 185,826 | | | 127,594 | |
| Miscellaneous - net | | (160,972) | | | 9,824 | | | (125,886) | |
| TOTAL | | 264,737 | | | 152,758 | | | 184,962 | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 375,295 | | | 373,480 | | | 350,227 | |
| Allowance for borrowed funds used during construction | | (14,996) | | | (11,550) | | | (12,878) | |
| TOTAL | | 360,299 | | | 361,930 | | | 337,349 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 1,067,589 | | | 693,017 | | | 774,393 | |
| | | | | | |
| Income taxes | | (205,781) | | | (162,853) | | | 120,409 | |
| | | | | | |
| NET INCOME | | 1,273,370 | | | 855,870 | | | 653,984 | |
| | | | | | |
| Net income attributable to noncontrolling interests | | 2,988 | | | 1,366 | | | — | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $1,270,382 | | | $854,504 | | | $653,984 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,198,229 |
| |
| $1,094,649 |
| |
| $1,396,985 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 185,816 |
| | 95,090 |
| | 291,666 |
|
| Purchased power | | 328,463 |
| | 297,902 |
| | 389,950 |
|
| Other operation and maintenance | | 243,480 |
| | 250,443 |
| | 261,255 |
|
| Taxes other than income taxes | | 95,051 |
| | 94,482 |
| | 94,152 |
|
| Depreciation and amortization | | 143,479 |
| | 136,214 |
| | 129,029 |
|
| Other regulatory charges (credits) - net | | (19,134 | ) | | (3,721 | ) | | 19,027 |
|
| TOTAL | | 977,155 |
| | 870,410 |
| | 1,185,079 |
|
| | | | | | | |
| OPERATING INCOME | | 221,074 |
| | 224,239 |
| | 211,906 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 9,667 |
| | 5,801 |
| | 3,095 |
|
| Interest and investment income | | 85 |
| | 656 |
| | 195 |
|
| Miscellaneous - net | | 510 |
| | (3,531 | ) | | (4,418 | ) |
| TOTAL | | 10,262 |
| | 2,926 |
| | (1,128 | ) |
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 51,260 |
| | 57,114 |
| | 57,842 |
|
| Allowance for borrowed funds used during construction | | (3,875 | ) | | (2,987 | ) | | (1,644 | ) |
| TOTAL | | 47,385 |
| | 54,127 |
| | 56,198 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 183,951 |
| | 173,038 |
| | 154,580 |
|
| | | | | | | |
| Income taxes | | 73,919 |
| | 63,854 |
| | 61,872 |
|
| | | | | | | |
| NET INCOME | | 110,032 |
| | 109,184 |
| | 92,708 |
|
| | | | |
|
| | |
| Preferred dividend requirements and other | | 953 |
| | 2,443 |
| | 2,828 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $109,079 |
| |
| $106,741 |
| |
| $89,880 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| Net Income | | $1,273,370 | | | $855,870 | | | $653,984 | |
| | | | | | |
| Other comprehensive income (loss) | | | | | | |
| Pension and other postretirement liabilities | | | | | | |
| (net of tax expense (benefit) of ($211), $17,351, and $1,523) | | (572) | | | 47,092 | | | 3,951 | |
| Other comprehensive income (loss) | | (572) | | | 47,092 | | | 3,951 | |
| | | | | | |
| Comprehensive Income | | 1,272,798 | | | 902,962 | | | 657,935 | |
| Net income attributable to noncontrolling interests | | 2,988 | | | 1,366 | | | — | |
| Comprehensive Income Applicable to Member's Equity | | $1,269,810 | | | $901,596 | | | $657,935 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $110,032 |
| |
| $109,184 |
| |
| $92,708 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 143,479 |
| | 136,214 |
| | 129,029 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 84,816 |
| | 60,986 |
| | 18,673 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (29,528 | ) | | (28,819 | ) | | 50,199 |
|
| Fuel inventory | | 5,266 |
| | 401 |
| | (8,537 | ) |
| Accounts payable | | 3,595 |
| | 33,733 |
| | (26,682 | ) |
| Taxes accrued | | 18,803 |
| | 20,579 |
| | (10,104 | ) |
| Interest accrued | | 1,248 |
| | 822 |
| | (2,341 | ) |
| Deferred fuel costs | | (25,487 | ) | | (114,711 | ) | | 105,560 |
|
| Other working capital accounts | | 5,115 |
| | (5,222 | ) | | (663 | ) |
| Provisions for estimated losses | | (9,676 | ) | | 6,378 |
| | (2,080 | ) |
| Other regulatory assets | | (17,412 | ) | | (3,626 | ) | | 39,582 |
|
| Other regulatory liabilities | | 405,395 |
| | (2,986 | ) | | 9,172 |
|
| Deferred tax rate change recognized as regulatory liability/asset | | (452,429 | ) | | — |
| | — |
|
| Pension and other postretirement liabilities | | (8,055 | ) | | (10,648 | ) | | (14,939 | ) |
| Other assets and liabilities | | (8,577 | ) | | 9,995 |
| | (7,298 | ) |
| Net cash flow provided by operating activities | | 226,585 |
| | 212,280 |
| | 372,279 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (427,616 | ) | | (310,356 | ) | | (235,894 | ) |
| Allowance for equity funds used during construction | | 9,667 |
| | 5,801 |
| | 3,095 |
|
| Insurance proceeds | | — |
| | — |
| | 12,932 |
|
| Changes in money pool receivable - net | | 8,962 |
| | 15,335 |
| | (25,286 | ) |
| Payment for purchase of assets | | (6,958 | ) | | — |
| | — |
|
| Other | | (1,281 | ) | | (224 | ) | | 26 |
|
| Net cash flow used in investing activities | | (417,226 | ) | | (289,444 | ) | | (245,127 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 148,185 |
| | 623,812 |
| | — |
|
| Retirement of long-term debt | | — |
| | (562,400 | ) | | — |
|
| Redemption of preferred stock | | — |
| | (30,000 | ) | | — |
|
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (26,000 | ) | | (24,000 | ) | | (40,000 | ) |
| Preferred stock | | (953 | ) | | (2,755 | ) | | (2,828 | ) |
| Other | | (1,329 | ) | | 3,736 |
| | (352 | ) |
| Net cash flow provided by (used in) financing activities | | 119,903 |
| | 8,393 |
| | (43,180 | ) |
| Net increase (decrease) in cash and cash equivalents | | (70,738 | ) | | (68,771 | ) | | 83,972 |
|
| Cash and cash equivalents at beginning of period | | 76,834 |
| | 145,605 |
| | 61,633 |
|
| Cash and cash equivalents at end of period | |
| $6,096 |
| |
| $76,834 |
| |
| $145,605 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $47,631 |
| |
| $53,693 |
| |
| $57,576 |
|
| Income taxes | |
| ($25,043 | ) | |
| ($12,487 | ) | |
| $61,333 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
|
(Page left blank intentionally)
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $1,607 |
| |
| $16 |
|
| Temporary cash investments | | 4,489 |
| | 76,818 |
|
| Total cash and cash equivalents | | 6,096 |
| | 76,834 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 72,039 |
| | 51,218 |
|
| Allowance for doubtful accounts | | (574 | ) | | (549 | ) |
| Associated companies | | 45,081 |
| | 45,973 |
|
| Other | | 9,738 |
| | 12,006 |
|
| Accrued unbilled revenues | | 54,256 |
| | 51,327 |
|
| Total accounts receivable | | 180,540 |
| | 159,975 |
|
| Deferred fuel costs | | 32,444 |
| | 6,957 |
|
| Fuel inventory - at average cost | | 45,606 |
| | 50,872 |
|
| Materials and supplies - at average cost | | 42,571 |
| | 41,146 |
|
| Prepayments and other | | 7,041 |
| | 8,873 |
|
| TOTAL | | 314,298 |
| | 344,657 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property - at cost (less accumulated depreciation) | | 4,592 |
| | 4,608 |
|
| Escrow accounts | | 31,969 |
| | 31,783 |
|
| TOTAL | | 36,561 |
| | 36,391 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 4,660,297 |
| | 4,321,214 |
|
| Property under capital lease | | 125 |
| | 1,590 |
|
| Construction work in progress | | 149,367 |
| | 118,182 |
|
| TOTAL UTILITY PLANT | | 4,809,789 |
| | 4,440,986 |
|
| Less - accumulated depreciation and amortization | | 1,681,306 |
| | 1,602,711 |
|
| UTILITY PLANT - NET | | 3,128,483 |
| | 2,838,275 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | — |
| | 38,284 |
|
| Other regulatory assets | | 397,909 |
| | 342,213 |
|
| Other | | 2,124 |
| | 2,320 |
|
| TOTAL | | 400,033 |
| | 382,817 |
|
| | | | | |
| TOTAL ASSETS | |
| $3,879,375 |
| |
| $3,602,140 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $1,273,370 | | | $855,870 | | | $653,984 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 864,225 | | | 852,521 | | | 818,389 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (99,812) | | | (70,379) | | | 175,700 | |
| Changes in working capital: | | | | | | |
| Receivables | | 55,140 | | | (53,434) | | | (58,466) | |
| Fuel inventory | | (15,959) | | | 1,099 | | | 7,722 | |
| Accounts payable | | (100,321) | | | (207,949) | | | 358,536 | |
| Taxes accrued | | 30,459 | | | (28,244) | | | 21,631 | |
| Interest accrued | | (9,680) | | | 8,284 | | | 803 | |
| Deferred fuel costs | | 134,383 | | | (113,809) | | | (43,124) | |
| Other working capital accounts | | (129,173) | | | (103,571) | | | (45,517) | |
| Changes in provisions for estimated losses | | (52,445) | | | 291,824 | | | (449) | |
| Changes in other regulatory assets | | 407,327 | | | 720,487 | | | (1,050,600) | |
| Changes in other regulatory liabilities | | 225,645 | | | (4,783) | | | (16,478) | |
| Effect of securitization on regulatory asset | | (491,150) | | | (1,190,338) | | | — | |
| | | | | | |
| Changes in pension and other postretirement liabilities | | (117,886) | | | (139,067) | | | (164,263) | |
| Other | | 57,997 | | | 358,997 | | | 394,658 | |
| Net cash flow provided by operating activities | | 2,032,120 | | | 1,177,508 | | | 1,052,526 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (1,624,181) | | | (2,568,113) | | | (3,621,775) | |
| Allowance for equity funds used during construction | | 32,160 | | | 26,252 | | | 28,648 | |
| Nuclear fuel purchases | | (162,079) | | | (122,020) | | | (85,419) | |
| Proceeds from sale of nuclear fuel | | 30,214 | | | 37,648 | | | 13,254 | |
| | | | | | |
| | | | | | |
| Payments to storm reserve escrow account | | (14,449) | | | (1,293,633) | | | — | |
| Receipts from storm reserve escrow account | | 64,036 | | | 1,000,228 | | | — | |
| Purchase of preferred membership interests of affiliate | | (1,457,676) | | | (3,163,572) | | | — | |
| Redemption of preferred membership interests of affiliate | | 125,002 | | | 1,390,587 | | | — | |
| Changes in securitization account | | — | | | — | | | 2,700 | |
| Proceeds from nuclear decommissioning trust fund sales | | 575,596 | | | 633,100 | | | 944,703 | |
| Investment in nuclear decommissioning trust funds | | (633,029) | | | (667,947) | | | (1,004,888) | |
| Changes in money pool receivable - net | | — | | | 14,539 | | | (1,113) | |
| Proceeds from sale of assets | | — | | | 5,000 | | | 15,000 | |
| Insurance proceeds received for property damages | | 19,493 | | | — | | | — | |
| Litigation proceeds from settlement agreement | | — | | | 5,695 | | | — | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — | | | — | | | 8,691 | |
| Decrease (increase) in other investments | | 5,457 | | | (5,475) | | | — | |
| Net cash flow used in investing activities | | (3,039,456) | | | (4,707,711) | | | (3,700,199) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 1,410,893 | | | 2,942,771 | | | 3,769,166 | |
| | | | | | |
| Retirement of long-term debt | | (2,699,235) | | | (3,167,832) | | | (1,895,091) | |
| Proceeds received by storm trusts related to securitization | | 1,457,676 | | | 3,163,572 | | | — | |
| Capital contributions from parent | | 1,457,676 | | | 1,000,000 | | | 125,000 | |
| | | | | | |
| | | | | | |
| Changes in money pool payable - net | | (69,948) | | | 226,114 | | | — | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (660,750) | | | (624,000) | | | (60,000) | |
| | | | | | |
| Other | | 57,183 | | | 27,618 | | | (849) | |
| Net cash flow provided by financing activities | | 953,495 | | | 3,568,243 | | | 1,938,226 | |
| Net increase (decrease) in cash and cash equivalents | | (53,841) | | | 38,040 | | | (709,447) | |
| Cash and cash equivalents at beginning of period | | 56,613 | | | 18,573 | | | 728,020 | |
| Cash and cash equivalents at end of period | | $2,772 | | | $56,613 | | | $18,573 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $376,353 | | | $353,697 | | | $337,926 | |
| Income taxes | | ($141,143) | | | ($82,463) | | | ($18,453) | |
| Non-cash investing activities: | | | | | | |
| Accrued construction expenditures | | $105,859 | | | $156,654 | | | $507,855 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2017 | | 2016 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Accounts payable: | | |
| | |
|
| Associated companies | |
| $55,689 |
| |
| $43,647 |
|
| Other | | 77,326 |
| | 80,227 |
|
| Customer deposits | | 83,654 |
| | 84,112 |
|
| Taxes accrued | | 82,843 |
| | 64,040 |
|
| Interest accrued | | 22,901 |
| | 21,653 |
|
| Other | | 12,785 |
| | 9,554 |
|
| TOTAL | | 335,198 |
| | 303,233 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 488,806 |
| | 861,331 |
|
| Accumulated deferred investment tax credits | | 8,867 |
| | 8,667 |
|
| Regulatory liability for income taxes - net | | 411,011 |
| | — |
|
| Asset retirement cost liabilities | | 9,219 |
| | 8,722 |
|
| Accumulated provisions | | 44,764 |
| | 54,440 |
|
| Pension and other postretirement liabilities | | 101,498 |
| | 109,551 |
|
| Long-term debt | | 1,270,122 |
| | 1,120,916 |
|
| Other | | 11,639 |
| | 20,108 |
|
| TOTAL | | 2,345,926 |
| | 2,183,735 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| Preferred stock without sinking fund | | 20,381 |
| | 20,381 |
|
| | | | | |
| COMMON EQUITY | | |
| | |
|
| Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2017 and 2016 | | 199,326 |
| | 199,326 |
|
| Capital stock expense and other | | 167 |
| | 167 |
|
| Retained earnings | | 978,377 |
| | 895,298 |
|
| TOTAL | | 1,177,870 |
| | 1,094,791 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,879,375 |
| |
| $3,602,140 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $2,255 | | | $50,318 | |
| Temporary cash investments | | 517 | | | 6,295 | |
| Total cash and cash equivalents | | 2,772 | | | 56,613 | |
| | | | |
| Accounts receivable: | | | | |
| Customer | | 264,776 | | | 339,291 | |
| Allowance for doubtful accounts | | (6,156) | | | (7,595) | |
| Associated companies | | 82,292 | | | 88,896 | |
| Other | | 74,685 | | | 53,241 | |
| Accrued unbilled revenues | | 202,173 | | | 199,077 | |
| Total accounts receivable | | 617,770 | | | 672,910 | |
| | | | |
| Deferred fuel costs | | 24,800 | | | 159,183 | |
| Fuel inventory | | 57,818 | | | 41,859 | |
| Materials and supplies - at average cost | | 652,180 | | | 555,860 | |
| Deferred nuclear refueling outage costs | | 96,047 | | | 53,833 | |
| | | | |
| | | | |
| Prepayments and other | | 71,613 | | | 76,646 | |
| TOTAL | | 1,523,000 | | | 1,616,904 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Investment in affiliate preferred membership interests | | 4,496,245 | | | 3,163,572 | |
| Decommissioning trust funds | | 2,107,384 | | | 1,779,090 | |
| Non-utility property - at cost (less accumulated depreciation) | | 404,043 | | | 350,723 | |
| Storm reserve escrow account | | 243,819 | | | 293,406 | |
| Other | | 9,367 | | | 19,679 | |
| TOTAL | | 7,260,858 | | | 5,606,470 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 27,800,467 | | | 27,498,136 | |
| Natural gas | | 315,658 | | | 301,719 | |
| | | | |
| Construction work in progress | | 592,803 | | | 736,969 | |
| Nuclear fuel | | 333,472 | | | 212,941 | |
| TOTAL UTILITY PLANT | | 29,042,400 | | | 28,749,765 | |
| Less - accumulated depreciation and amortization | | 10,570,707 | | | 10,087,942 | |
| UTILITY PLANT - NET | | 18,471,693 | | | 18,661,823 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 1,648,852 | | | 2,056,179 | |
| Deferred fuel costs | | 168,122 | | | 168,122 | |
| Other | | 36,945 | | | 35,057 | |
| TOTAL | | 1,853,919 | | | 2,259,358 | |
| | | | |
| TOTAL ASSETS | | $29,109,470 | | | $28,144,555 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2017, 2016, and 2015 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Capital Stock Expense and Other | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2014 |
| $199,326 |
| |
| ($690 | ) | |
| $763,534 |
| |
| $962,170 |
|
| Net income | — |
| | — |
| | 92,708 |
| | 92,708 |
|
| Common stock dividends | — |
| | — |
| | (40,000 | ) | | (40,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2015 |
| $199,326 |
| |
| ($690 | ) | |
| $813,414 |
| |
| $1,012,050 |
|
| Net income | — |
| | — |
| | 109,184 |
| | 109,184 |
|
| Common stock dividends | — |
| | — |
| | (24,000 | ) | | (24,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,443 | ) | | (2,443 | ) |
| Preferred stock redemption | — |
| | 857 |
| | (857 | ) | | — |
|
| Balance at December 31, 2016 |
| $199,326 |
| |
| $167 |
| |
| $895,298 |
| |
| $1,094,791 |
|
| Net income | — |
| | — |
| | 110,032 |
| | 110,032 |
|
| Common stock dividends | — |
| | — |
| | (26,000 | ) | | (26,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (953 | ) | | (953 | ) |
| Balance at December 31, 2017 |
| $199,326 |
| |
| $167 |
| |
| $978,377 |
| |
| $1,177,870 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
| | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $1,400,000 | | | $1,010,000 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 283,016 | | | 356,688 | |
| Other | | 467,414 | | | 589,355 | |
| Customer deposits | | 167,905 | | | 161,666 | |
| Taxes accrued | | 66,463 | | | 36,004 | |
| | | | |
| Interest accrued | | 91,656 | | | 101,336 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
| Other | | 87,468 | | | 72,525 | |
| TOTAL | | 2,563,922 | | | 2,327,574 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 2,391,442 | | | 2,374,878 | |
| Accumulated deferred investment tax credits | | 93,242 | | | 97,868 | |
| Regulatory liability for income taxes - net | | 193,754 | | | 337,836 | |
| Other regulatory liabilities | | 1,407,689 | | | 1,037,962 | |
| Decommissioning | | 1,836,240 | | | 1,736,801 | |
| Accumulated provisions | | 263,869 | | | 316,314 | |
| Pension and other postretirement liabilities | | 271,928 | | | 389,631 | |
| Long-term debt | | 8,020,689 | | | 9,688,922 | |
| | | | |
| Other | | 493,176 | | | 343,321 | |
| TOTAL | | 14,972,029 | | | 16,323,533 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| EQUITY | | | | |
| | | | |
Member’s equity | | 11,473,614 | | | 9,406,343 | |
| Accumulated other comprehensive income | | 54,798 | | | 55,370 | |
| Noncontrolling interests | | 45,107 | | | 31,735 | |
| TOTAL | | 11,573,519 | | | 9,493,448 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $29,109,470 | | | $28,144,555 | |
| | | | |
| See Notes to Financial Statements. | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,198,229 |
| |
| $1,094,649 |
| |
| $1,396,985 |
| |
| $1,524,193 |
| |
| $1,334,540 |
|
| Net income |
| $110,032 |
| |
| $109,184 |
| |
| $92,708 |
| |
| $74,821 |
| |
| $82,159 |
|
| Total assets |
| $3,879,375 |
| |
| $3,602,140 |
| |
| $3,477,407 |
| |
| $3,358,625 |
| |
| $3,234,875 |
|
| Long-term obligations (a) |
| $1,290,503 |
| |
| $1,141,924 |
| |
| $972,058 |
| |
| $1,097,182 |
| |
| $1,092,786 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $502 |
| |
| $459 |
| |
| $565 |
| |
| $585 |
| |
| $527 |
|
| Commercial | 423 |
| | 374 |
| | 465 |
| | 481 |
| | 432 |
|
| Industrial | 159 |
| | 134 |
| | 164 |
| | 175 |
| | 156 |
|
| Governmental | 41 |
| | 38 |
| | 47 |
| | 47 |
| | 42 |
|
| Total retail | 1,125 |
| | 1,005 |
| | 1,241 |
| | 1,288 |
| | 1,157 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | 1 |
| | 75 |
| | 153 |
| | 92 |
|
| Non-associated companies | 18 |
| | 30 |
| | 10 |
| | 14 |
| | 24 |
|
| Other | 55 |
| | 59 |
| | 71 |
| | 69 |
| | 62 |
|
| Total |
| $1,198 |
| |
| $1,095 |
| |
| $1,397 |
| |
| $1,524 |
| |
| $1,335 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,308 |
| | 5,617 |
| | 5,661 |
| | 5,672 |
| | 5,629 |
|
| Commercial | 4,783 |
| | 4,894 |
| | 4,913 |
| | 4,821 |
| | 4,815 |
|
| Industrial | 2,536 |
| | 2,493 |
| | 2,283 |
| | 2,297 |
| | 2,265 |
|
| Governmental | 421 |
| | 439 |
| | 433 |
| | 414 |
| | 409 |
|
| Total retail | 13,048 |
| | 13,443 |
| | 13,290 |
| | 13,204 |
| | 13,118 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | — |
| | 1,419 |
| | 2,657 |
| | 1,543 |
|
| Non-associated companies | 857 |
| | 1,021 |
| | 261 |
| | 193 |
| | 304 |
|
| Total | 13,905 |
| | 14,464 |
| | 14,970 |
| | 16,054 |
| | 14,965 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2023, 2022, and 2021 |
| | | | | |
| | Noncontrolling Interests | | Member’s Equity | | Accumulated Other Comprehensive Income | | Total |
| | (In Thousands) |
| | | | | | | |
| Balance at December 31, 2020 | $— | | | $7,453,361 | | | $4,327 | | | $7,457,688 | |
| Net income | — | | | 653,984 | | | — | | | 653,984 | |
| | | | | | | |
| Other comprehensive income | — | | | — | | | 3,951 | | | 3,951 | |
| | | | | | | |
| Capital contribution from parent | — | | | 125,000 | | | — | | | 125,000 | |
| | | | | | | |
| Common equity distributions | — | | | (60,000) | | | — | | | (60,000) | |
| | | | | | | |
| | | | | | | |
| Other | — | | | (51) | | | — | | | (51) | |
| Balance at December 31, 2021 | $— | | | $8,172,294 | | | $8,278 | | | $8,180,572 | |
| Net income | 1,366 | | | 854,504 | | | — | | | 855,870 | |
| | | | | | | |
| Other comprehensive income | — | | | — | | | 47,092 | | | 47,092 | |
| Beneficial interest in storm trust | 31,636 | | | — | | | — | | | 31,636 | |
| Non-cash contribution from parent | — | | | 3,597 | | | — | | | 3,597 | |
| Capital contribution from parent | — | | | 1,000,000 | | | — | | | 1,000,000 | |
| Common equity distributions | — | | | (624,000) | | | — | | | (624,000) | |
| Distribution to LURC | (1,267) | | | — | | | — | | | (1,267) | |
| | | | | | | |
| | | | | | | |
| Other | — | | | (52) | | | — | | | (52) | |
| Balance at December 31, 2022 | $31,735 | | | $9,406,343 | | | $55,370 | | | $9,493,448 | |
| Net income | 2,988 | | | 1,270,382 | | | — | | | 1,273,370 | |
| Other comprehensive loss | — | | | — | | | (572) | | | (572) | |
| Beneficial interest in storm trust | 14,577 | | | — | | | — | | | 14,577 | |
| | | | | | | |
| Capital contribution from parent | — | | | 1,457,676 | | | — | | | 1,457,676 | |
| Common equity distributions | — | | | (660,750) | | | — | | | (660,750) | |
| Distributions to LURC | (4,193) | | | — | | | — | | | (4,193) | |
| | | | | | | |
| | | | | | | |
| Other | — | | | (37) | | | — | | | (37) | |
| Balance at December 31, 2023 | $45,107 | | | $11,473,614 | | | $54,798 | | | $11,573,519 | |
| | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
ENTERGY NEW ORLEANS,MISSISSIPPI, LLC AND SUBSIDIARIES
MANAGEMENT’SMANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Internal Restructuring
In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans, Inc. to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring was subject to regulatory review and approval by the City Council and the FERC. In May 2017 the City Council adopted a resolution approving the proposed internal restructuring pursuant to an agreement in principle with the City Council advisors and certain intervenors. Pursuant to the agreement in principle, Entergy New Orleans would credit retail customers $10 million in 2017, $1.4 million in the first quarter of the year after the transaction closes, and $117,500 each month in the second year after the transaction closes until such time as new base rates go into effect as a result of the anticipated 2018 base rate case. Entergy New Orleans began crediting retail customers in June 2017. In June 2017 the FERC approved the transaction and, pursuant to the agreement in principle, Entergy New Orleans will provide additional credits to retail customers of $5 million in each of the years 2018, 2019, and 2020.
In November 2017, pursuant to the agreement in principle, Entergy New Orleans undertook a multi-step restructuring, including the following:
Entergy New Orleans, Inc. redeemed its outstanding preferred stock at a price of approximately $21 million, which included a call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans, Inc. converted from a Louisiana corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans, Inc. allocated substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power assumed substantially all of the liabilities of Entergy New Orleans, Inc. in a transaction regarded as a merger under the TXBOC. Entergy New Orleans, Inc. remained in existence and held the membership interests in Entergy New Orleans Power.
Entergy New Orleans, Inc. contributed the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power is a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
In December 2017, Entergy New Orleans, Inc. changed its name to Entergy Utility Group, Inc., and Entergy New Orleans Power then changed its name to Entergy New Orleans, LLC. Entergy New Orleans, LLC holds substantially all of the assets, and has assumed substantially all of the liabilities, of Entergy New Orleans, Inc. The restructuring was accounted for as a transaction between entities under common control.
Results of Operations
Net Income
20172023 Compared to 20162022
Net incomeEarnings Applicable to Member’s Equity
Earnings decreased $4.3$5.4 million primarily due to higher taxesdepreciation and amortization expenses, lower volume/weather, higher interest expense, lower other than income, taxes, lower net revenue, and a higher effective income tax rate, partially offset by lower other operation and maintenance expenses, and higher taxes other income.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2016 Compared to 2015
Netthan income increased $3.9 million primarily due to higher net revenue,taxes. The decrease was partially offset by higher depreciation and amortization expenses, higher interest expense, and lower other income.retail electric price.
Net RevenueOperating Revenues
2017 Compared to 2016
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenueoperating revenues comparing 20172023 to 2016.
| | | | | |
| Amount |
| | | (In Millions) |
| 2022 operating revenues | Amount$1,624.2 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (In Millions)95.8 | |
| |
2016 net revenue |
| $317.2 |
|
| Retail electric price | (6.458.9 | | )
Volume/weatherRetail one-time bill credit | (4.336.7 | | )
OtherVolume/weather | 5.4(13.1) | |
2017 net revenue2023 operating revenues |
$1,802.5 | | $311.9
|
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 a net decreaseincreases in the purchased powerformula rate plan rates effective August 2022, April 2023, and capacity acquisition cost recovery rider. There was an increase in the rider primarily due to credits to customers as part of the Entergy New Orleans internal restructuring agreement in principle, effective with the first billing cycle of June 2017, partially offset by lower credits to customers in 2017 related to the retirement of Michoud Units 2 and 3.July 2023. See Note 2 to the financial statements for further discussion of the credits associatedformula rate plan filings.
The retail one-time bill credit represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to retail customers during the September 2022 billing cycle as a result of the System Energy settlement agreement with Entergy New Orleans’s internal restructuringthe MPSC. There is no effect on net income as the reduction in operating revenues was offset by a reduction in fuel and purchased power expenses. See Note 2 to the financial statements for discussion of the settlement agreement and the Michoud retirement.MPSC directive related to the disbursement of settlement proceeds.
The volume/weather variance is primarily due to the effect of less favorable weather on residential sales and commercial sales, partially offset by an increasea decrease in weather-adjusted residential and commercial usage, resulting from a 1% increase in the average number of residential and commercial electric customers.
2016 Compared to 2015
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
2015 net revenue |
| $293.9 |
|
Retail electric price | 39.0 |
|
Net gas revenue | (2.5 | ) |
Volume/weather | (5.1 | ) |
Other | (8.1 | ) |
2016 net revenue |
| $317.2 |
|
The retail electric price variance is primarily due to an increase in the purchased power and capacity acquisition cost recovery rider, as approvedpartially offset by the City Council, effective with the first billing cycleeffect of March 2016, primarilymore favorable weather on commercial sales.
Entergy New Orleans,Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy Mississippi for the years ended December 31, 2023 and 2022 are as follows:
related to the purchase of Power Block 1 of the Union Power Station. | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | | |
| Residential | 5,460 | | | 5,679 | | | (4) | |
| Commercial | 4,640 | | | 4,586 | | | 1 | |
| Industrial | 2,347 | | | 2,359 | | | (1) | |
| Governmental | 407 | | | 414 | | | (2) | |
| Total retail | 12,854 | | | 13,038 | | | (1) | |
| Sales for resale: | | | | | |
| Non-associated companies | 4,598 | | | 2,914 | | | 58 | |
| Total | 17,452 | | | 15,952 | | | 9 | |
See Note 1419 to the financial statements for additional discussion of the Union Power Station purchase.Entergy Mississippi’s operating revenues.
The net gas revenue variance is primarily due to the effect of less favorable weather on residential and commercial sales.
The volume/weather variance is primarily due to a decrease of 112 GWh, or 2%, in billed electricity usage, partially offset by the effect of favorable weather on commercial sales and a 2% increase in the average number of electric customers.
Other Income Statement Variances
2017 Compared to 2016
Other operation and maintenance expenses decreasedincreased primarily due to:
a decrease•an increase of $7.9$6.6 million in fossil-fueled generationcontract costs related to operational performance, customer service, and organizational health initiatives;
•an increase of $5.1 million in loss provisions;
•an increase of $4.4 million in bad debt expense;
•an increase of $3.1 million in power delivery expenses primarily due to higher vegetation maintenance costs, partially offset by a lower outage costs at Power Block 1scope of the Union Power Stationwork performed in 20172023 as compared to 2016, the deactivation of Michoud Units 22022; and 3 effective May 2016, and asbestos loss provisions in 2016;
a decrease of $4.5 million in other loss provisions; and•several individually insignificant items.
a decrease of $2.8 million due to lower write-offs of uncollectible customer accounts.
The decreaseincrease was partially offset by:
an increase of $4 million in distribution expenses primarily due to higher labor costs, including contract labor, and higher vegetation maintenance costs; and
an increase of $1.3 million in energy efficiency costs.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes and higher local franchise taxes. Ad valorem taxes increased primarily due to higher assessments, including the assessment of Arkansas ad valorem taxes on the Union Power Station beginning in 2017. Local franchise taxes increased primarily due to higher electric retail revenues in 2017 as compared to 2016.
Other income increased primarily due to a decrease in charitable contributions made in 2017 as compared to 2016.
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
•a decrease of $6.1$5.8 million due to lowerin transmission equalization expenses, ascosts allocated under the System Agreement as compared to the same period in 2015 primarily due to the termination of the System Agreement. See Note 2 to the financial statements for further discussion on the System Agreement termination;by MISO;
•a decrease of $4.4 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm cost recovery; and
a decrease of $3.1$5.3 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits service costs as a result of an increase in the discount raterates used to value the benefitbenefits liabilities, lower health and welfare costs, including higher prescription drug rebates in second quarter 2023, and a refinementrevision to estimated incentive compensation expense in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs.first quarter 2023. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
benefits costs; and
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The decrease was partially offset by:
an increase of $5.7$5.3 million in fossil-fuelednon-nuclear generation expenses primarily due to an increase as a resultlower scope of the purchase of Power Block 1 of the Union Power Stationwork, including during plant outages, performed in March 2016, partially offset by a decrease as a result of the deactivation of Michoud Units 2 and 3 effective May 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
an increase of $3.1 million in loss provisions; and
an increase of $2.8 million due to higher write-offs of uncollectible customer accounts in 20162023 as compared to 2015.2022.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and increases in local franchise taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the purchaseSunflower Solar facility, which was placed in service in September 2022.
Other regulatory charges (credits) - net includes regulatory credits of Power Block 1$22.6 million, recorded in third quarter 2022, to reflect the effects of the Union Power Stationjoint stipulation reached in March 2016,the 2022 formula rate plan filing proceeding and regulatory credits of $18.2 million, recorded in fourth quarter 2022, to reflect that the 2022 estimated earned
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
return was below the formula bandwidth. See Note 2 to the financial statements for discussion of the formula rate plan filings.
Other income (deductions) decreased primarily due to lower interest income from carrying costs related to the deferred fuel balance and an increase in non-qualified pension settlement charges recorded in 2023 and other postretirement benefit non-service costs as a result of the amortization of 2022 trust asset losses. The decrease was partially offset by the retirementtiming of Michoud Units 2charitable donations and 3 effective May 2016.an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs.
Interest expense increased primarily due to the issuance of $110$300 million of 5.50%5.0% Series first mortgage bonds in March 2016May 2023 and the issuance$150 million unsecured term loan drawn in June 2022, of $98.7which $50 million was repaid in May 2023 and $100 million was repaid in December 2023. The increase was partially offset by the repayment of $250 million of storm cost recovery3.10% Series mortgage bonds in July 2015.June 2023.
Net loss attributable to noncontrolling interest reflects the earnings or losses attributable to the noncontrolling partner of the tax equity partnership for the Sunflower Solar facility under HLBV accounting. Entergy Mississippi recorded regulatory charges of $9.1 million in 2023 and $21.4 million in 2022 to defer the difference between the losses allocated to the tax equity partner under the HLBV method of accounting and the earnings/losses that would have been allocated to the tax equity partner under its respective ownership percentage in the partnership. See Note 51 to the financial statements for details on long-term debt.discussion of the HLBV method of accounting.
Other income decreased primarily due to an increase in charitable contributions made in 2016 as compared to 2015.
Income Taxes
The effective income tax rates were 23.0% for 2017, 2016,2023 and 2015 were 42.8%, 37.0% and 35.9%, respectively.23.7% for 2022. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35%21% to the effective income tax rates.rates and for additional discussion regarding income taxes.
2022 Compared to 2021
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, 2022, filed with the SEC onFebruary 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $16,979 | | | $47,627 | | | $18 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 559,391 | | | 405,649 | | | 350,960 | |
| Investing activities | (527,978) | | | (620,740) | | | (686,654) | |
| Financing activities | (41,762) | | | 184,443 | | | 383,303 | |
| Net increase (decrease) in cash and cash equivalents | (10,349) | | | (30,648) | | | 47,609 | |
| | | | | |
| Cash and cash equivalents at end of period | $6,630 | | | $16,979 | | | $47,627 | |
2023 Compared to 2022
Operating Activities
Net cash flow provided by operating activities increased $153.7 million in 2023 primarily due to:
•lower 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;
•higher collections from customers; and
•a decrease of $12.2 million in pension contributions in 2023. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
The increase was partially offset by:
•the receipt of $235 million in settlement proceeds in 2022, of which $198.3 million was applied to the under-recovered deferred fuel balance. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery and the System Energy settlement agreement with the MPSC;
•income tax payments of $50.9 million in 2023 as compared to income tax refunds of $5.4 million in 2022. Entergy Mississippi made income tax payments in 2023 and received income tax refunds in 2022, each in accordance with an intercompany income tax allocation agreement;
•an increase of $13.9 million in storm spending in 2023; and
•an increase of $10.7 million in interest paid.
Investing Activities
Net cash flow used in investing activities decreased $92.8 million in 2023 primarily due to:
•the initial payment of approximately $105.1 million in May 2022 as compared to the substantial completion payment of approximately $30.4 million in April 2023 and the final payment of approximately $4.7 million in October 2023 for the purchase of the Sunflower Solar facility by a consolidated tax equity partnership. See Note 14 to the financial statements for discussion of the Sunflower Solar facility purchase;
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•the receipt of $34.5 million from the storm reserve escrow account in 2023. See Note 2 to the financial statements for discussion of the storm escrow disbursement;
•a decrease of $20.2 million in non-nuclear generation construction expenditures primarily due to a lower scope of work, including during plant outages, performed in 2023 as compared to 2022;
•a decrease of $17.8 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2023; and
•money pool activity.
The decrease was partially offset by an increase of $46.8 million in transmission construction expenditures primarily due to increased investment in the reliability and infrastructure of Entergy Mississippi’s transmission system in 2023 and an increase of $27.5 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2023.
Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased $26.9 million in 2023 compared to decreasing by $13.6 million in 2022. The money pool is an intercompany cash management program that makes possible intercompany borrowing and lending arrangements, including to reduce the Registrant Subsidiaries’ need for external short-term borrowings.
Financing Activities
Entergy Mississippi’s financing activities used $41.8 million of cash in 2023 compared to providing $184.4 million of cash in 2022 primarily due to the following activity:
•proceeds of $150 million received in June 2022 from an unsecured term loan due December 2023 as compared to repayments of $150 million on the unsecured term loan in 2023;
•the repayment, prior to maturity, of $250 million of 3.10% Series mortgage bonds in June 2023;
•$40 million in common equity distributions paid in 2023 in order to maintain Entergy Mississippi’s capital structure;
•money pool activity; and
•the issuance of $300 million of 5.0% Series mortgage bonds in May 2023.
Increases in Entergy Mississippi’s payable to the money pool are a source of cash flow, and Entergy Mississippi’s payable to the money pool increased $73.8 million in 2023.
See Note 5 to the financial statements for details on long-term debt.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy Mississippi’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Mississippi is primarily due to the net retirement of long-term debt in 2023 and net income in 2023.
| | | | | | | | | | | |
| | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 50.5 | % | | 53.4 | % |
| Effect of subtracting cash | (0.1 | %) | | (0.2 | %) |
| Net debt to net capital (non-GAAP) | 50.4 | % | | 53.2 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Mississippi seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy 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 reduced 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.
| | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation | $130 | | | $440 | | | $750 | |
| Transmission | 185 | | | 200 | | | 180 | |
| Distribution | 335 | | | 325 | | | 295 | |
| Utility Support | 50 | | | 60 | | | 60 | |
| Total | $700 | | | $1,025 | | | $1,285 | |
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes investments in generation projects to modernize, decarbonize, and diversify Entergy Mississippi’s portfolio, as well as to support customer growth; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting renewables expansion and customer growth; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, government actions, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Following are the amounts of Entergy Mississippi’s existing debt and lease obligations (includes estimated interest payments).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2024 | | 2025 | | 2026 | | 2027-2028 | | After 2028 |
| | (In Millions) |
| Long-term debt (a) | $182 | | | $81 | | | $81 | | | $675 | | | $2,853 | |
| Operating leases (b) | $8 | | | $7 | | | $5 | | | $7 | | | $2 | |
| Finance leases (b) | $3 | | | $3 | | | $3 | | | $4 | | | $24 | |
(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 $15 million to its qualified pension plans and approximately $178 thousand to other postretirement health care and life insurance plans in 2024, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024, valuations are completed, which is expected by April 1, 2024. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Entergy Mississippi has $1.9 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
In addition, Entergy 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.
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;
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
•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.
| | | | | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | 2021 | | 2020 |
| (In Thousands) |
| ($73,769) | | $26,879 | | $40,456 | | ($16,516) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has a credit facility in the amount of $150 million scheduled to expire in July 2025. As of December 31, 2023, there were no cash borrowings outstanding under the credit facility. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO and for other purposes. As of December 31, 2023, $20.0 million in MISO letters of credit and $1.0 million in a non-MISO letter 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 April 2025 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.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.
Filings with the MPSC
Retail Rates
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
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 showed a $95.4 million rate increase was 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, was capped at 4% of retail revenues, which equated to a revenue change of $44.3 million. The 2021 evaluation report also included $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 were not subject to the 4% cap and resulted in a total change in formula rate plan revenues of $48.2 million. The 2020 look-back filing compared actual 2020 results to the approved benchmark return on rate base and reflected the need for a $16.8 million interim increase in formula rate plan revenues. In addition, the 2020 look-back filing included an interim capacity adjustment true-up for the Choctaw Generating Station, which increased the look-back interim rate adjustment by $1.7 million. These interim rate adjustments totaled $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 were 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 was 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 included $1.7 million related to the Choctaw Generating Station and $3.7 million of COVID-19 non-bad debt expenses. The joint stipulation also included Entergy Mississippi’s quantification and methodology for calculating incremental COVID-19 bad debt expenses and provided for Entergy Mississippi to continue to defer these incremental COVID-19 bad debt expenses through December 2021. 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
In March 2022, Entergy Mississippi submitted its formula rate plan 2022 test year filing and 2021 look-back filing showing Entergy Mississippi’s earned return for the historical 2021 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2022 calendar year to be below the formula rate plan bandwidth. The 2022 test year filing showed a $69 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 6.70% return on rate base, within the formula rate plan bandwidth. The change in formula rate plan revenues, however, was capped at 4% of retail revenues, which equated to a revenue change of $48.6 million. The 2021 look-back filing compared actual 2021 results to the approved benchmark return on rate base and reflected the need for a $34.5 million interim increase in formula rate plan revenues. In fourth quarter 2021, Entergy Mississippi recorded a regulatory asset of $19 million to reflect the then-current estimate in connection with the look-back feature of the formula rate plan. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $24.3 million interim rate increase, reflecting a cap equal to 2% of 2021 retail revenues, effective in April 2022. With the implementation of the interim formula rate plan rates, Entergy Mississippi began recovery of the bad debt expense deferral resulting from the COVID-19 pandemic over a three-year period.
In June 2022, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2022 test year filing that resulted in a total rate increase of $48.6 million. Pursuant to the joint stipulation, Entergy Mississippi’s 2021 look-back filing reflected an earned return on rate base of 5.99% in calendar year 2021, which was below the look-back bandwidth, resulting in a $34.3 million increase in the formula rate plan revenues on an interim basis through June 2023. In July 2022 the MPSC approved the joint stipulation with rates effective in August 2022. In July 2022, Entergy Mississippi recorded regulatory credits of $22.6 million to reflect
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
the effects of the joint stipulation. In August 2022 an intervenor filed a statutorily-authorized direct appeal to the Mississippi Supreme Court seeking review of the MPSC’s July 2022 order approving the joint stipulation confirming Entergy Mississippi’s 2022 formula rate plan filing. Formula rate plan rates are not stayed or otherwise impacted while the appeal is pending.
In July 2022 the MPSC directed Entergy Mississippi to flow $14.1 million of the power management rider over-recovery balance to customers beginning in August 2022 through December 2022 to mitigate the bill impact of the increase in formula rate plan revenues.
2023 Formula Rate Plan Filing
In March 2023, Entergy Mississippi submitted its formula rate plan 2023 test year filing and 2022 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2022 calendar year to be below the formula rate plan bandwidth and projected earned return for the 2023 calendar year to be below the formula rate plan bandwidth. The 2023 test year filing showed a $39.8 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 6.67%, within the formula rate plan bandwidth. The 2022 look-back filing compared actual 2022 results to the approved benchmark return on rate base and reflected the need for a $19.8 million temporary increase in formula rate plan revenues, including the refund of a $1.3 million over-recovery resulting from the demand-side management costs true-up for 2022. In fourth quarter 2022, Entergy Mississippi recorded a regulatory asset of $18.2 million in connection with the look-back feature of the formula rate plan to reflect that the 2022 estimated earned return was below the formula rate plan bandwidth. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $27.9 million interim rate increase, reflecting a cap equal to 2% of 2022 retail revenues, effective in April 2023.
In May 2023, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed a 2023 test year filing resulting in a total revenue increase of $26.5 million for 2023. Pursuant to the joint stipulation, Entergy Mississippi’s 2022 look-back filing reflected an earned return on rate base of 6.10% in calendar year 2022, which was below the look-back bandwidth, resulting in a $19.0 million increase in the formula rate plan revenues on an interim basis through June 2024. Entergy Mississippi recorded a regulatory credit of $0.8 million in June 2023 to reflect the increase in the look-back regulatory asset. In addition, certain long-term service agreement and conductor handling costs were authorized for realignment from the formula rate plan to the annual power management and grid modernization riders effective January 2023, resulting in regulatory credits recorded in June 2023 of $4.1 million and $4.3 million, respectively. Also, the amortization of Entergy Mississippi’s COVID-19 bad debt expense deferral was suspended for calendar year 2023 and will resume in 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.
Fuel and purchased power cost recovery
Entergy Mississippi’s rate schedules include an energy cost recovery rider and a power management rider, both of which are adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi recovers fuel and purchased energy costs through its energy cost recovery rider and recovers costs associated with natural gas hedging and capacity payments through its power management rider. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
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
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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 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.
See “Complaints Against System Energy - System Energy Settlement with the MPSC” in Note 2 to the financial statements for discussion of the settlement agreement filed with the FERC in June 2022. The settlement, which was approved by the FERC in November 2022, provided for a refund of $235 million from System Energy to Entergy Mississippi. In July 2022 the MPSC directed the disbursement of settlement proceeds, ordering Entergy Mississippi to provide a one-time $80 bill credit to each of its approximately 460,000 retail customers to be effective during the September 2022 billing cycle and to apply the remaining proceeds to Entergy Mississippi’s under-recovered deferred fuel balance. In accordance with the MPSC’s directive, Entergy Mississippi provided approximately $36.7 million in customer bill credits as a result of the settlement. In November 2022, Entergy Mississippi applied the remaining settlement proceeds in the amount of approximately $198.3 million to Entergy Mississippi’s under-recovered deferred fuel balance.
Entergy Mississippi had a deferred fuel balance of approximately $291.7 million under the energy cost recovery rider as of July 31, 2022, along with an over-recovery balance of $51.1 million under the power management rider. Without further action, Entergy Mississippi anticipated a year-end deferred fuel balance of approximately $200 million after application of a portion of the System Energy settlement proceeds, as discussed above. In September 2022, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider. Entergy Mississippi proposed five monthly incremental adjustments to the net energy cost factor designed to collect the under-recovered fuel balance as of July 31, 2022 and to reflect the recovery of a higher natural gas price. Entergy Mississippi also proposed five monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance as of July 31, 2022. In October 2022 the MPSC approved modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider. The MPSC approved dividing the energy cost recovery rider interim adjustment into two components that would allow Entergy Mississippi to (1) recover a natural gas fuel rate that is better aligned with current prices; and (2) recover the estimated under-recovered deferred fuel balance as of September 30, 2022 over a period of 20 months. The MPSC approved six monthly incremental adjustments to the net energy cost factor designed to reflect the recovery of a higher natural gas price. The MPSC also approved six monthly incremental adjustments to the power management adjustment factor designed to flow through to customers the over-recovered power management rider balance. In accordance with the order of the MPSC, Entergy Mississippi did not file an annual redetermination of the energy cost recovery rider or the power management rider in November 2022.
In June 2023 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2023 formula rate plan filing. The stipulation directed Entergy Mississippi to make a compliance filing to revise its power management cost adjustment factor, to revise its grid modernization cost adjustment factor, and to include a revision to reduce the net energy cost factor to a level necessary to reflect an average natural gas price of $4.50 per MMBtu. The MPSC approved the compliance filing in June 2023, effective for July 2023 bills. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2023 Formula Rate Plan Filing” in Note 2 to the financial statements for further discussion of the 2023 formula rate plan filing and the joint stipulation agreement.
In November 2023 Entergy Mississippi filed its annual redeterminations of the energy cost factor and the power management cost adjustment factor. The calculation of the annual factor for the energy cost recovery rider included a projected over-recovery balance of approximately $142 million at the end of January 2024. The calculation of the annual factor for the power management rider included a projected under-recovery of $47 million
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
at the end of January 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.
RenewABLE Community Option
In January 2022, Entergy Mississippi filed its RenewABLE Community Option (Schedule RCO), an offering for qualifying non-residential customers to subscribe to renewable resource capacity to satisfy their environmental, sustainability, and governance goals. The MPSC approved Schedule RCO in December 2022. Registration for the Schedule RCO launched in May 2023 and subscriptions as of December 31, 2023 totaled 17.9 MW of the 40 MW available.
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.
In December 2023 Entergy Mississippi filed a Notice of Storm Escrow Disbursement and Request for Interim Relief notifying the MPSC that Entergy Mississippi had requested disbursement of approximately $34.5 million of storm escrow funds from its restricted storm escrow account. The filing also requested authorization from the MPSC, on a temporary basis, that the $34.5 million of storm escrow funds be credited to Entergy Mississippi’s storm damage provision, pending the MPSC’s review of Entergy Mississippi’s storm-related costs, and that Entergy Mississippi continue to bill its monthly storm damage provision without suspension in the event the storm damage provision balance exceeds $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage reserve exceeded $15 million upon receipt of the storm escrow funds. Because the MPSC had not entered an order on Entergy Mississippi’s filing on the requested relief to continue billing this provision, Entergy Mississippi suspended billing the monthly storm damage provision effective with February 2024 bills.
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.
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy Mississippi’s financial statements in conformity with GAAP 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 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 these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy Mississippi’s financial position, results of operations, or cash flows.
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.
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 affected 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 2024 Qualified Pension Cost | | Impact on 2023 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $256 | | $6,670 |
| Rate of return on plan assets | | (0.25%) | | $723 | | $— |
| Rate of increase in compensation | | 0.25% | | $264 | | $1,383 |
Entergy Mississippi, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
| | | | | | | | | | | | | | | | | | | | |
| Actuarial Assumption | | Change in Assumption | | Impact on 2024 Postretirement Benefits Cost | | Impact on 2023 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $20 | | $1,031 |
| Health care cost trend | | 0.25% | | $60 | | $701 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Employer Contributions
Total qualified pension cost for Entergy Mississippi in 2023 was $19.7 million, including $12.2 million in settlement costs. Entergy Mississippi anticipates 2024 qualified pension cost to be $3.3 million. Entergy Mississippi contributed $21.1 million to its qualified pension plans in 2023 and estimates 2024 pension contributions will be approximately $15 million, although the 2024 required pension contributions will be known with more certainty when the January 1, 2024 valuations are completed, which is expected by April 1, 2024.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2023 was $2.5 million. Entergy Mississippi expects 2024 postretirement health care and life insurance benefit income of approximately $3.7 million. Entergy Mississippi contributed $646 thousand to its other postretirement plan in 2023 and estimates 2024 contributions will be approximately $178 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 the “New Accounting Pronouncements” section of Note 1 to the financial statements for a discussion of new accounting pronouncements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the member and Board of Directors of
Entergy Mississippi, LLC and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Entergy Mississippi, LLC and Subsidiaries (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, cash flows and changes in equity (pages 391 through 396 and applicable items in pages 47 through 238), for each of the three years in the period ended December 31, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Rate and Regulatory Matters — Entergy Mississippi, LLC and Subsidiaries — Refer to Note 2 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Mississippi Public Service Commission (the “MPSC”), which has jurisdiction with respect to the rates of electric companies in Mississippi, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.
The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the MPSC and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the MPSC and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.
We identified the impact of rate regulation as a critical audit matter due to the 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, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities involved specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the MPSC and the FERC, recovery in future rates of regulatory assets and refunds or future reductions in rates related to regulatory liabilities 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 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 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 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 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 and orders issued, 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.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 23, 2024
We have served as the Company’s auditor since 2001.
| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | | $1,802,533 | | | $1,624,234 | | | $1,406,346 | |
| | | | | | |
| OPERATING EXPENSES | | | | | | |
| Operation and Maintenance: | | | | | | |
| Fuel, fuel-related expenses, and gas purchased for resale | | 563,296 | | | 252,760 | | | 181,511 | |
| Purchased power | | 281,761 | | | 322,674 | | | 298,034 | |
| Other operation and maintenance | | 320,192 | | | 314,902 | | | 298,129 | |
| | | | | | |
| Taxes other than income taxes | | 150,921 | | | 137,541 | | | 111,712 | |
| Depreciation and amortization | | 262,624 | | | 246,063 | | | 226,545 | |
| Other regulatory charges (credits) - net | | (111,376) | | | 38,017 | | | 5,913 | |
| TOTAL | | 1,467,418 | | | 1,311,957 | | | 1,121,844 | |
| | | | | | |
| OPERATING INCOME | | 335,115 | | | 312,277 | | | 284,502 | |
| | | | | | |
| OTHER INCOME (DEDUCTIONS) | | | | | | |
| Allowance for equity funds used during construction | | 8,552 | | | 6,125 | | | 8,101 | |
| Interest and investment income | | 2,275 | | | 508 | | | 53 | |
| Miscellaneous - net | | (13,231) | | | (3,619) | | | (8,791) | |
| TOTAL | | (2,404) | | | 3,014 | | | (637) | |
| | | | | | |
| INTEREST EXPENSE | | | | | | |
| Interest expense | | 99,857 | | | 86,960 | | | 75,124 | |
| Allowance for borrowed funds used during construction | | (3,479) | | | (2,800) | | | (3,416) | |
| TOTAL | | 96,378 | | | 84,160 | | | 71,708 | |
| | | | | | |
| INCOME BEFORE INCOME TAXES | | 236,333 | | | 231,131 | | | 212,157 | |
| | | | | | |
| Income taxes | | 54,364 | | | 54,864 | | | 45,323 | |
| | | | | | |
| NET INCOME | | 181,969 | | | 176,267 | | | 166,834 | |
| | | | | | |
| Net loss attributable to noncontrolling interest | | (10,302) | | | (21,355) | | | — | |
| | | | | | |
| EARNINGS APPLICABLE TO MEMBER'S EQUITY | | $192,271 | | | $197,622 | | | $166,834 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
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| | | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| | | For the Years Ended December 31, |
| | | 2023 | | 2022 | | 2021 |
| | | (In Thousands) |
| | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | | $181,969 | | | $176,267 | | | $166,834 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 262,624 | | | 246,063 | | | 226,545 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 28,990 | | | 54,850 | | | 64,868 | |
| Changes in assets and liabilities: | | | | | | |
| Receivables | | 3,627 | | | (65,843) | | | 10,260 | |
| Fuel inventory | | (648) | | | (5,237) | | | 6,806 | |
| Accounts payable | | (41,101) | | | 49,101 | | | 27,068 | |
| Taxes accrued | | (9,771) | | | 18,632 | | | (1,811) | |
| Interest accrued | | 3,329 | | | 925 | | | (3,606) | |
| Deferred fuel costs | | 273,856 | | | (21,333) | | | (136,569) | |
| Other working capital accounts | | (23,813) | | | 2,632 | | | (9,522) | |
| Provisions for estimated losses | | 1,972 | | | (519) | | | (8,476) | |
| Other regulatory assets | | (59,616) | | | (57,028) | | | 4,909 | |
| Other regulatory liabilities | | (59,513) | | | 20,165 | | | 21,930 | |
| | | | | | |
| Pension and other postretirement liabilities | | (49,223) | | | (35,299) | | | (51,828) | |
| Other assets and liabilities | | 46,709 | | | 22,273 | | | 33,552 | |
| Net cash flow provided by operating activities | | 559,391 | | | 405,649 | | | 350,960 | |
| INVESTING ACTIVITIES | | | | | | |
| Construction expenditures | | (562,118) | | | (534,020) | | | (654,352) | |
| Allowance for equity funds used during construction | | 8,552 | | | 6,125 | | | 8,101 | |
| | | | | | |
| | | | | | |
| Payment for purchase of assets | | (35,094) | | | (105,149) | | | — | |
| Changes in money pool receivable - net | | 26,879 | | | 13,577 | | | (40,456) | |
| Receipt from storm reserve escrow account | | 34,493 | | | — | | | — | |
| | | | | | |
| | | | | | |
| | | | | | |
| Decrease (increase) in other investments | | (690) | | | (1,273) | | | 53 | |
| Net cash flow used in investing activities | | (527,978) | | | (620,740) | | | (686,654) | |
| FINANCING ACTIVITIES | | | | | | |
| Proceeds from the issuance of long-term debt | | 396,833 | | | 249,266 | | | 398,284 | |
| Retirement of long-term debt | | (500,000) | | | (100,000) | | | — | |
| Capital contributions from noncontrolling interest | | 25,708 | | | 24,702 | | | — | |
| Changes in money pool payable - net | | 73,769 | | | — | | | (16,516) | |
| | | | | | |
| | | | | | |
| | | | | | |
| Common equity distributions paid | | (40,000) | | | — | | | — | |
| | | | | | |
| Other | | 1,928 | | | 10,475 | | | 1,535 | |
| Net cash flow provided by (used in) financing activities | | (41,762) | | | 184,443 | | | 383,303 | |
| Net increase (decrease) in cash and cash equivalents | | (10,349) | | | (30,648) | | | 47,609 | |
| Cash and cash equivalents at beginning of period | | 16,979 | | | 47,627 | | | 18 | |
| Cash and cash equivalents at end of period | | $6,630 | | | $16,979 | | | $47,627 | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | |
| Cash paid (received) during the period for: | | | | | | |
| Interest - net of amount capitalized | | $93,961 | | | $83,291 | | | $76,245 | |
| Income taxes | | $50,869 | | | ($5,396) | | | ($19,672) | |
| Noncash investing activities: | | | | | | |
| Accrued construction expenditures | | $16,342 | | | $59,474 | | | $26,498 | |
| | | | | | |
| See Notes to Financial Statements. | | | | | | |
| | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | | $30 | | | $26 | |
| Temporary cash investments | | 6,600 | | | 16,953 | |
| Total cash and cash equivalents | | 6,630 | | | 16,979 | |
| Accounts receivable: | | | | |
| Customer | | 121,389 | | | 99,504 | |
| Allowance for doubtful accounts | | (3,312) | | | (2,472) | |
| Associated companies | | 4,997 | | | 37,673 | |
| Other | | 17,697 | | | 34,564 | |
| Accrued unbilled revenues | | 71,465 | | | 73,473 | |
| Total accounts receivable | | 212,236 | | | 242,742 | |
| Deferred fuel costs | | — | | | 143,211 | |
| | | | |
| Fuel inventory - at average cost | | 16,196 | | | 15,548 | |
| Materials and supplies - at average cost | | 95,526 | | | 84,346 | |
| | | | |
| Prepayments and other | | 12,740 | | | 9,603 | |
| TOTAL | | 343,328 | | | 512,429 | |
| | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | |
| Non-utility property - at cost (less accumulated depreciation) | | 4,497 | | | 4,512 | |
| Storm reserve escrow account | | 656 | | | 33,549 | |
| Other | | — | | | 910 | |
| TOTAL | | 5,153 | | | 38,971 | |
| | | | |
| UTILITY PLANT | | | | |
| Electric | | 7,455,145 | | | 7,079,849 | |
| | | | |
| Construction work in progress | | 139,635 | | | 170,191 | |
| TOTAL UTILITY PLANT | | 7,594,780 | | | 7,250,040 | |
| Less - accumulated depreciation and amortization | | 2,346,327 | | | 2,264,786 | |
| UTILITY PLANT - NET | | 5,248,453 | | | 4,985,254 | |
| | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | |
| Regulatory assets: | | | | |
| | | | |
| Other regulatory assets | | 579,076 | | | 519,460 | |
| Other | | 51,996 | | | 22,650 | |
| TOTAL | | 631,072 | | | 542,110 | |
| | | | |
| TOTAL ASSETS | | $6,228,006 | | | $6,078,764 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | |
| | | December 31, |
| | | 2023 | | 2022 |
| | | (In Thousands) |
| | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | | $100,000 | | | $400,000 | |
| | | | |
| Accounts payable: | | | | |
| Associated companies | | 133,571 | | | 60,532 | |
| Other | | 92,659 | | | 176,162 | |
| Customer deposits | | 92,637 | | | 89,668 | |
| Taxes accrued | | 115,134 | | | 124,905 | |
| | | | |
| Interest accrued | | 21,537 | | | 18,208 | |
| Deferred fuel costs | | 130,645 | | | — | |
| | | | |
| Other | | 26,463 | | | 38,908 | |
| TOTAL | | 712,646 | | | 908,383 | |
| | | | |
| NON-CURRENT LIABILITIES | | | | |
| Accumulated deferred income taxes and taxes accrued | | 821,744 | | | 780,030 | |
| Accumulated deferred investment tax credits | | 13,811 | | | 14,591 | |
| Regulatory liability for income taxes - net | | 188,714 | | | 202,058 | |
| | | | |
| Other regulatory liabilities | | 33,696 | | | 79,865 | |
| Asset retirement cost liabilities | | 8,229 | | | 7,797 | |
| Accumulated provisions | | 39,481 | | | 37,509 | |
| Pension and other postretirement liabilities | | — | | | 23,742 | |
| Long-term debt | | 2,129,510 | | | 1,931,096 | |
| Other | | 71,961 | | | 53,156 | |
| TOTAL | | 3,307,146 | | | 3,129,844 | |
| | | | |
| Commitments and Contingencies | | | | |
| | | | |
| | | | |
| | | | |
| EQUITY | | | | |
| Member's equity | | 2,189,461 | | | 2,037,190 | |
| Noncontrolling interest | | 18,753 | | | 3,347 | |
| TOTAL | | 2,208,214 | | | 2,040,537 | |
| | | | |
| TOTAL LIABILITIES AND EQUITY | | $6,228,006 | | | $6,078,764 | |
| | | | |
| See Notes to Financial Statements. | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| For the Years Ended December 31, 2023, 2022, and 2021 |
| | | | | |
| | Noncontrolling Interest | | Member's Equity | | Total |
| | (In Thousands) |
| | | | | |
| Balance at December 31, 2020 | $— | | | $1,672,734 | | | $1,672,734 | |
| Net income | — | | | 166,834 | | | 166,834 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Balance at December 31, 2021 | $— | | | $1,839,568 | | | $1,839,568 | |
| Net income (loss) | (21,355) | | | 197,622 | | | 176,267 | |
| Capital contributions from noncontrolling interest | 24,702 | | | — | | | 24,702 | |
| | | | | |
| | | | | |
| | | | | |
| Balance at December 31, 2022 | $3,347 | | | $2,037,190 | | | $2,040,537 | |
| Net income (loss) | (10,302) | | | 192,271 | | | 181,969 | |
| Common equity distributions | — | | | (40,000) | | | (40,000) | |
| Capital contributions from noncontrolling interest | 25,708 | | | — | | | 25,708 | |
| | | | | |
| | | | | |
| Balance at December 31, 2023 | $18,753 | | | $2,189,461 | | | $2,208,214 | |
| | | | | |
| See Notes to Financial Statements. | | | | | |
ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
2023 Compared to 2022
Net Income
Net income increased $164.8 million primarily due to a $198.4 million reduction in income tax expense in 2023 as a result of the resolution of the 2016-2018 IRS audit, partially offset by a $60 million regulatory charge ($43.8 million net-of-tax) to reflect credits expected to be provided to customers, and higher retail electric price. The increase was partially offset by higher other operation and maintenance expenses. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.
Operating Revenues
Following is an analysis of the change in operating revenues comparing 2023 to 2022:
| | | | | |
| Amount |
| (In Millions) |
| 2022 operating revenues | $997.3 | |
| Fuel, rider, and other revenues that do not significantly affect net income | (174.6) | |
| Volume/weather | 0.5 | |
| Storm restoration carrying costs | 5.2 | |
| Retail electric price | 15.5 | |
| |
| |
| 2023 operating revenues | $843.9 | |
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 volume/weather variance is insignificant and primarily due to the effect of more favorable weather on commercial sales and an increase in weather-adjusted residential usage, partially offset by the effect of less favorable weather on residential sales.
Storm restoration carrying costs represent the equity component of storm restoration carrying costs, recorded in fourth quarter 2023, recognized as part of the City Council’s approval of the Hurricane Ida storm cost certification report in December 2023. See Note 2 to the financial statements for further discussion of the storm cost certification.
The retail electric price variance is primarily due to an increase in formula rate plan rates effective September 2022 in accordance with the terms of the 2022 formula rate plan filing. See Note 2 to the financial statements for further discussion of the formula rate plan filing.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Total electric energy sales for Entergy New Orleans for the years ended December 31, 2023 and 2022 are as follows:
| | | | | | | | | | | | | | | | | |
| 2023 | | 2022 | | % Change |
| (GWh) | |
| Residential | 2,364 | | | 2,410 | | | (2) | |
| Commercial | 2,126 | | | 2,096 | | | 1 | |
| Industrial | 423 | | | 411 | | | 3 | |
| Governmental | 783 | | | 789 | | | (1) | |
| Total retail | 5,696 | | | 5,706 | | | — | |
| Sales for resale: | | | | | |
| Non-associated companies | 2,818 | | | 2,298 | | | 23 | |
| Total | 8,514 | | | 8,004 | | | 6 | |
See Note 19 to the financial statements for additional discussion of Entergy New Orleans’s operating revenues.
Other Income Statement Variances
Other operation and maintenance expenses increased primarily due to:
•an increase of $4.6 million in non-nuclear generation expenses primarily due to a higher scope of work performed in 2023 as compared to 2022;
•an increase of $4.5 million resulting from a gain on the sale of NOx allowances in 2022;
•an increase of $3.9 million in power delivery expenses primarily due to higher reliability costs and higher vegetation maintenance costs in 2023 as compared to 2022; and
•an increase of $3 million in contract costs related to operational performance, customer service, and organizational health initiatives.
The increase was partially offset by a decrease of $3 million in energy efficiency expenses primarily due to the timing of recovery from customers and lower energy efficiency costs.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other regulatory charges (credits) - net includes a regulatory charge of $60 million, recorded in fourth quarter 2023, to reflect credits expected to be provided to customers as a result of the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit.
Other income increased primarily due to higher interest earned on money pool investments. The increase was partially offset by a decrease of $2.3 million due to the recognition of storm restoration carrying costs in 2022 related to Hurricane Ida and an increase in other postretirement benefit non-service costs as a result of the amortization of 2022 trust asset losses and non-qualified pension settlement charges. See Note 2 to the financial statements for further discussion of storm restoration costs. See “Critical Accounting Estimates– Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs.
Interest expense increased primarily due to a higher fixed interest rate on Entergy New Orleans’s unsecured term loan and interest on the $34 million regulatory liability recorded when Entergy New Orleans received a refund from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation. The
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
increase was partially offset by the repayment of $100 million of 3.9% Series mortgage bonds in July 2023. See Note 2 to the financial statements for further discussion of the refund and the related proceedings.
The effective income tax rates were (487.5%) for 2023 and 27.5% for 2022. 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.
2022 Compared to 2021
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, 2022, filed with the SEC on February 24, 2023, for discussion of results of operations for 2022 compared to 2021.
Income Tax Legislation and Regulation
See the “Income Tax Legislation and Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of income tax legislation and regulation.
Planned Sale of Gas Distribution Business
See the “Planned Sale of Gas Distribution Businesses” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the Tax Cutspurchase and Jobs Act,sale agreement for the federal income tax legislation enactedsale of Entergy New Orleans’s gas distribution business.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2023, 2022, and 2021 were as follows:
| | | | | | | | | | | | | | | | | |
| | 2023 | | 2022 | | 2021 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period | $4,464 | | | $42,862 | | | $26 | |
| | | | | |
| Net cash provided by (used in): | | | | | |
| Operating activities | 202,956 | | | 363,763 | | | 78,808 | |
| Investing activities | (18,802) | | | (403,790) | | | (169,920) | |
| Financing activities | (188,592) | | | 1,629 | | | 133,948 | |
| Net increase (decrease) in cash and cash equivalents | (4,438) | | | (38,398) | | | 42,836 | |
| | | | | |
| Cash and cash equivalents at end of period | $26 | | | $4,464 | | | $42,862 | |
2023 Compared to 2022
Operating Activities
Net cash flow provided by operating activities decreased $160.8 million in 2023 primarily due to:
•net proceeds of $201.8 million received from the LURC in December 2017. Note 3 to the financial statements contains additional discussion of the effect of the Act on 2017 results of operations and financial position, the provisions of the Act, and the uncertainties associated with accounting for the Act, and2022 from securitization. See Note 2 to the financial statements discusses proceedings commenced or other responses by Entergy’s regulators tofor further discussion of the Act.storm securitization;
•lower receipts from associated companies in 2022;
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, 2017, 2016, and 2015 were as follows:
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $103,068 |
| |
| $88,876 |
| |
| $42,389 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 127,797 |
| | 205,211 |
| | 105,068 |
|
| Investing activities | (109,500 | ) | | (322,681 | ) | | (173,460 | ) |
| Financing activities | (88,624 | ) | | 131,662 |
| | 114,879 |
|
| Net increase (decrease) in cash and cash equivalents | (70,327 | ) |
| 14,192 |
|
| 46,487 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $32,741 |
|
|
| $103,068 |
|
|
| $88,876 |
|
Operating Activities
Net cash flow provided by operating activities decreased $77.4 million in 2017 primarily due to a decrease•an increase of $77.3$13.6 million in income tax refundstaxes paid in 2017 compared to 2016 and the timing of collections from customers and payments to vendors.2023. Entergy New Orleans hadmade net income tax refundspayments in 20172023 primarily related to the resolution of the 2016-2018 IRS audit and 2016 in accordance with an intercompanyestimated federal and state income tax allocation agreement. The 2016 income tax refunds resulted primarilytaxes. See Note 3 to the financial statements for further discussion of the resolution of the 2016-2018 IRS audit; and
•lower collections from deductible temporary differences. customers.
The decrease was partially offset by an increase due toby:
•lower 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;
•the refund of $34 million received from System Energy in January 2023 related to the sale-leaseback renewal costs and depreciation litigation as calculated in System Energy’s January 2023 compliance report filed with the FERC. See Note 2 to the financial statements for further discussion of the refund and the related proceedings; and
Net cash flow provided by operating activities increased $100.1•a decrease of $18.7 million in 2016storm spending primarily due to income tax refunds of $86 millionHurricane Ida restoration efforts in 2016 as compared to income tax payments of $8.1 million in 2015. Entergy New Orleans had income tax refunds in 2016 and income tax payments in 2015 in accordance with an intercompany income tax allocation agreement. The 2016 income tax refunds resulted primarily from deductible temporary differences.2022.
Investing Activities
Net cash flow used in investing activities decreased $213.2$385 million in 20172023 primarily due to:
•money pool activity;
•a decrease of $71.3 million in net payments to the purchasestorm reserve escrow account in 2023; and
•a decrease of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase. The decrease was partially offset by an increase of $16.7$42.9 million in distribution construction expenditures primarily due to a higher scope of work performedcapital expenditures for Hurricane Ida storm restoration efforts in 2017 as compared to 2016.
Net cash flow used in investing activities increased $149.2 million in 2016 primarily due to the purchase of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. The increase was2022, partially offset by a depositincreased investment in the reliability and infrastructure of $63.9 million into the storm reserve escrow accountEntergy New Orleans’s distribution system in July 2015 and money pool activity. See Note 14 to the financial statements for discussion of the Union Power Station purchase. See Note 5 to the financial statements for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs.2023.
Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $1.6$147.3 million in 20162023 compared to increasing $15.4by $110.8 million in 2015.2022. The money pool is an inter-companyintercompany cash management program that makes possible intercompany borrowing arrangementand lending arrangements, and the money pool and other borrowing arrangements are designed to reduce the Utility subsidiaries’ need forRegistrant Subsidiaries’ dependence on external short-term borrowingsborrowings.
Financing Activities
Entergy New Orleans’s financing activities used $188.6 million of cash in 2023 compared to providing $1.6 million of cash in 2022 primarily due to the following activity:
•$125 million in common equity distributions paid in 2023 in order to maintain Entergy New Orleans’s capital structure;
•the repayment, at maturity, of $100 million of 3.90% Series mortgage bonds in July 2023;
•additional borrowings of $15 million in May 2023 on an unsecured term loan due June 2024; and
•money pool activity.
Increases in Entergy New Orleans’s payable to the money pool are a source of cash flow, and Entergy New Orleans’s payable to the money pool increased $21.7 million in 2023.
See Note 5 to the financial statements for details on long-term debt.
2022 Compared to 2021
See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
December 31, 2022, filed with the SEC on February 24, 2023, for discussion of operating, investing, and financing cash flow activities for 2022 compared to 2021.
Financing Activities
Capital Structure
Entergy New Orleans’s financing activities used $88.6 million of cash in 2017 compareddebt to providing $131.7 million in 2016 primarily due to the following activity:
the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016;
an increase of $55.5 million in common equity distributions in 2017 as compared to 2016. Common equity distributions in 2017 increased primarily as a result of Entergy New Orleans’s cash position in excess of its working capital requirements. There were no common equity distributions in first quarter 2016 in anticipation of the purchase of Power Block 1 of the Union Power Station in March 2016;
a decrease of $27.8 million in capital contributions received from Entergy Corporation in 2017 compared to 2016. The 2017 contribution was made in consideration of Entergy New Orleans’s upcoming capital requirements. The 2016 contribution was made in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and
the redemptions of $7.8 million of 4.75% Series preferred stock, $6 million of 5.56% Series preferred stock, and $6 million of 4.36% Series preferred stock in 2017 in connection with the internal restructuring, as discussed above.
See Note 14 to the financial statements for discussion of the Union Power Station purchase.
Net cash flow provided by financing activities increased $16.8 million in 2016 primarily due to:
the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchaseratio is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction;
the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016; and
the issuance of $85 million of 4% Series first mortgage bonds in May 2016. Entergy New Orleans used the proceeds to pay, prior to maturity, its $33.271 million of 5.6% Series first mortgage bonds due September 2024 and to pay, prior to maturity, its $37.772 million of 5.65% Series first mortgage bonds due September 2029.
The increase was offset by:
the issuance of $98.7 million of storm costs recovery bonds in July 2015;
a $47.8 million capital contribution received from Entergy Corporation in 2016 as compared to an $87.5 million capital contribution received from Entergy Corporation in 2015, both in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and
an increase of $11.5 million in common equity distributions in 2016. Common equity distributions were lower in 2015 in anticipation of the purchase of Power Block 1 of the Union Power Station.
See Note 5 to the financial statements for more details on long-term debt.
Entergy New Orleans, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy New Orleans’s capitalization is balanced between equity and debt as shown in the following table. The increasedecrease in the debt to capital ratio for Entergy New Orleans is primarily due to net income in 2023 and the redemptionsnet retirement of preferred stocklong-term debt in 2017. 2023, partially offset by common equity distributions of $125 million in 2023.
| | | | December 31, 2017 | | December 31, 2016 |
| December 31,
2023 | | | December 31,
2023 | | December 31,
2022 |
| Debt to capital | 51.3 | % | | 50.1 | % | Debt to capital | 45.8 | % | | 52.6 | % |
| Effect of excluding securitization bonds | (4.7 | %) | | (5.2 | %) | Effect of excluding securitization bonds | (0.2 | %) | | (0.6 | %) |
| Debt to capital, excluding securitization bonds (a) | 46.6 | % | | 44.9 | % |
| Debt to capital, excluding securitization bonds (non-GAAP) (a) | | Debt to capital, excluding securitization bonds (non-GAAP) (a) | 45.6 | % | | 52.0 | % |
| Effect of subtracting cash | (2.4 | %) | | (8.0 | %) | Effect of subtracting cash | — | % | | (0.1 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 44.2 | % | | 36.9 | % |
| Net debt to net capital, excluding securitization bonds (non-GAAP) (a) | | Net debt to net capital, excluding securitization bonds (non-GAAP) (a) | 45.6 | % | | 51.9 | % |
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 Entergy Louisiana.an associated company. Capital consists of debt preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy New Orleans uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend,distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce dividends,distributions, or both, to maintain its targeted 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 dividends,reduced distributions, Entergy New Orleans may receive equity contributions to maintain the targetedits capital structure.
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations..
As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.