Item 1A. , 1B, and 1C

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Item 1A. , 1B, and 1C

Entergy Corporation, Utility operating companies, and System Energy

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

Winter Storm Fern

See the “Winter Storm Fern” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Winter Storm Fern. Entergy Arkansas’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $50 million to $60 million, with the majority of the costs being capital. Natural gas purchases for Entergy Arkansas for January 2026 are $74 million compared to natural gas purchases for January 2025 of $25 million.

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $118.0 million primarily due to a $131.8 million ($99.1 million net-of-tax) charge, recorded in first quarter 2024, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the opportunity sales proceeding in March 2024, higher volume/weather, and higher retail electric price, partially offset by higher depreciation and amortization expenses, higher other operation and maintenance expenses, higher interest expense, an $18.3 million reduction in income tax expense in third quarter 2024 as a result of the resolution of an Arkansas state income tax audit, and higher taxes other than income taxes. See Note 2 to the financial statements for discussion of the opportunity sales proceeding. See Note 3 to the financial statements for discussion of the resolution of the Arkansas state income tax audit.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:


			Amount
			(In Millions)
2024 operating revenues			$2,460.2
Fuel, rider, and other revenues that do not significantly affect net income			61.3
Volume/weather			107.3
Retail one-time bill credit			92.3
Retail electric price			62.9
2025 operating revenues			$2,784.0

Entergy Arkansas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The volume/weather variance is primarily due to an increase in industrial and residential usage. The increase in industrial usage is primarily due to an increase in demand from large industrial customers, primarily in the primary metals and technology industries, and an increase in demand from small industrial customers. The increase in residential usage is primarily due to an increase in customers.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The retail one-time bill credit variance represents the disbursement of settlement proceeds in the form of a one-time bill credit provided to Entergy Arkansas’s retail customers during the August 2024 billing cycle through the Grand Gulf credit rider as a result of the System Energy settlement with the APSC. There is no effect on net income because Entergy Arkansas previously recorded a regulatory liability for the effects of the System Energy settlement with the APSC. See Note 2 to the financial statements for discussion of the System Energy settlement with the APSC and discussion of the Grand Gulf credit rider.

The retail electric price variance is primarily due to an increase in formula rate plan rates effective January 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.

Total electric energy sales for Entergy Arkansas for the years ended December 31, 2025 and 2024 are as follows:


	2025	2024	% Change
	(GWh)
Residential	7,980	7,658	4
Commercial	5,639	5,583	1
Industrial	12,095	10,179	19
Governmental	189	185	2
Total retail	25,903	23,605	10
Sales for resale:
Associated companies	1,913	2,039	(6)
Non-associated companies	4,545	4,058	12
Total	32,361	29,702	9

See Note 19 to the financial statements for additional discussion of Entergy Arkansas’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses increased primarily due to:

an increase of $14.0 million in power delivery expenses primarily due to higher vegetation maintenance costs;
an increase of $13.9 million in non-nuclear generation expenses primarily due to a higher scope of work, including during plant outages, in 2025 as compared to 2024;
an increase of $6.1 million in bad debt expense;
the expensing of $5.0 million of certain wind and solar project costs associated with the decision to evaluate alternative generation solutions; and
several individually insignificant items.

The increase was partially offset by contract costs of $11.5 million in 2024 related to operational performance, customer service, and organizational health initiatives and a decrease of $10.9 million in energy efficiency expenses primarily due to the timing of recovery from customers.

Asset write-offs includes a $131.8 million charge, recorded in first quarter 2024, to reflect the write-off of a previously recorded regulatory asset as a result of an adverse decision in the opportunity sales proceeding in March 2024. See Note 2 to the financial statements for discussion of the opportunity sales proceeding.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Walnut Bend Solar facility, which was placed in service in September 2024, and the West Memphis Solar facility and the Driver Solar facility, which were placed in service in December 2024.

Other regulatory charges (credits) - net includes:

the reversal in third quarter 2024 of a $92.3 million regulatory liability recognized for the obligation to return to customers the refund from the System Energy settlement with the APSC. The reversal of the regulatory liability offsets a reduction in gross revenues from the retail one-time bill credits provided to customers in the August 2024 billing cycle through the Grand Gulf credit rider. See Note 2 to the financial statements for discussion of the System Energy settlement with the APSC and discussion of the Grand Gulf credit rider;
a regulatory credit of $28.3 million, recorded in fourth quarter 2025, to reflect the amount of the 2024 historical year netting adjustment to be collected from Entergy Arkansas’s customers during the 2026 rate effective period as included in the 2025 formula rate plan filing. See Note 2 to the financial statements for discussion of the 2025 formula rate plan filing; and
a regulatory credit of $15.5 million, recorded in fourth quarter 2024, to reflect the amount of the 2023 historical year netting adjustment to be collected from Entergy Arkansas’s customers during the 2025 rate effective period as included in the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.

In addition, Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and nuclear decommissioning trust earnings plus asset retirement obligation-related costs collected in revenue.

Interest expense increased primarily due to the issuance of $400 million of 5.45% Series mortgage bonds in May 2024 and an additional $300 million in a reopening of the same series in May 2025.

The effective income tax rates were 19.8% for 2025 and 18.9% for 2024. 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.

2024 Compared to 2023

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, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.

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 Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:


	2025	2024	2023
	(In Thousands)
Cash and cash equivalents at beginning of period	$4,747	$3,632	$5,278

Net cash provided by (used in):
Operating activities	1,335,048	978,680	941,021
Investing activities	(1,197,122)	(1,732,630)	(1,032,952)
Financing activities	132,897	755,065	90,285
Net increase (decrease) in cash and cash equivalents	270,823	1,115	(1,646)

Cash and cash equivalents at end of period	$275,570	$4,747	$3,632

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $356.4 million in 2025 primarily due to:

higher collections from customers;
net cash proceeds of $242.6 million received by Entergy Arkansas in 2025, including $215.2 million of proceeds received from Entergy Arkansas’s transfer of 2024 nuclear and solar production tax credits to third parties in 2025 and net cash receipts of $27.4 million from affiliates in 2025 in accordance with the Unit Power Sales Agreement and the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by Entergy Arkansas and affiliates to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear and solar production tax credits;
income tax refunds of $29.7 million in 2025 compared to income tax payments of $9.5 million in 2024. Entergy Arkansas received income tax refunds in 2025 and made income tax payments in 2024, each in accordance with Entergy’s tax allocation agreement;
a decrease of $23.7 million in spending on nuclear refueling outages in 2025 as compared to 2024; and
a decrease of $19.6 million in pension contributions in 2025. 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:

higher fuel and purchased power payments. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
the timing of payments to vendors; and
the receipt of $92.7 million in settlement proceeds in 2024 as a result of the System Energy settlement with the APSC, which was subsequently refunded to retail customers in third quarter 2024 with one-time bill credits through the Grand Gulf credit rider. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the APSC and the Grand Gulf credit rider.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Investing Activities

Net cash flow used in investing activities decreased $535.5 million in 2025 primarily due to:

the initial and substantial completion payments totaling approximately $392.8 million in 2024 for the purchase of the Driver Solar facility;
the initial and substantial completion payments totaling approximately $240.4 million in 2024 for the purchase of the West Memphis Solar facility;
the initial and substantial completion payments totaling approximately $185.5 million in 2024 for the purchase of the Walnut Bend Solar facility;
a decrease in cash used of $38.2 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; and
a decrease of $30.0 million in transmission construction expenditures primarily due to decreased spending on various transmission projects in 2025.

The decrease was partially offset by:

an increase of $201.0 million in non-nuclear generation construction expenditures primarily due to higher spending on the Ironwood Power Station (formerly Lake Catherine Unit 5) project and the Jefferson Power Station project;
an increase of $92.0 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2025;
cash collateral of $37.0 million posted in 2025 to support Entergy Arkansas’s obligations to MISO; and
money pool activity.

Increases in Entergy Arkansas’s receivable from the money pool are a use of cash flow, and Entergy Arkansas’s receivable from the money pool increased $21.7 million in 2025. 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 14 to the financial statements for discussion of the Driver Solar facility, the West Memphis Solar facility, and the Walnut Bend Solar facility purchases.

Financing Activities

Net cash flow provided by financing activities decreased $622.2 million in 2025 primarily due to:

the issuances of $400 million of 5.45% Series mortgage bonds and $400 million of 5.75% Series mortgage bonds, each in May 2024;
capital contributions of approximately $695 million received from Entergy Corporation in 2024 to partially finance the acquisitions of the Walnut Bend Solar facility, the West Memphis Solar facility, and the Driver Solar facility;
the issuance of $70 million of 5.54% Series O notes by the Entergy Arkansas nuclear fuel company variable interest entity in March 2024; and
a decrease of $16.6 million in advance payments from customers for construction related to transmission, distribution, and generator interconnection agreements.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The decrease was partially offset by:

the repayment, at maturity, of $375 million of 3.70% Series mortgage bonds in June 2024;
the issuance of $300 million of 5.45% Series mortgage bonds in May 2025;
a decrease of $120 million in common equity distributions paid in 2025 in order to maintain Entergy Arkansas’s capital structure;
money pool activity; and
a decrease in net repayments of $38.9 million on the nuclear fuel company variable interest entity’s credit facility.

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 $15.2 million in 2025 compared to decreasing by $130.2 million in 2024.

See Note 5 to the financial statements for additional details of long-term debt.

2024 Compared to 2023

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, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.

Capital Structure

Entergy Arkansas’s debt to capital ratio is shown in the following table.


	December 31, 2025		December 31, 2024
Debt to capital	53.7	%	53.6	%
Effect of subtracting cash	(1.3	%)	—	%
Net debt to net capital (non-GAAP)	52.4	%	53.6	%

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition. The net debt to net capital ratio is a non-GAAP measure. Entergy Arkansas also uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy Arkansas may receive equity contributions to maintain its capital structure.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Uses of Capital

Entergy Arkansas requires capital resources for:

construction and other capital investments;
debt maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
distribution and interest payments.

Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.


	2026	2027	2028	2029
	(In Millions)
Planned construction and capital investment:
Generation	$1,510	$1,870	$1,240	$555
Transmission	85	140	175	215
Distribution	310	310	380	400
Utility Support	65	55	65	50
Total	$1,970	$2,375	$1,860	$1,220

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, expand, and diversify Entergy Arkansas’s portfolio, as well as to support customer growth, including Ironwood Power Station (formerly Lake Catherine Unit 5), Jefferson Power Station, and Arkansas Cypress Solar; investments in ANO 1 and 2; distribution and Utility support spending to improve reliability and customer experience; transmission spending to improve reliability while also supporting customer growth and 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, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Arkansas’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Arkansas’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect Entergy Arkansas’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy Arkansas’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.

Entergy Arkansas has incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on its current and planned capital projects. Entergy Arkansas is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments).


	2026	2027	2028	2029-2030	After 2030
	(In Millions)
Long-term debt (a)	$900	$218	$545	$443	$7,054
Operating leases (b)	$20	$18	$15	$17	$13
Finance leases (b)	$7	$6	$6	$9	$21

(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 $29.7 million to its qualified pension plans and approximately $710 thousand to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026. 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 $235.4 million of unrecognized tax benefits net of unused tax attributes plus interest for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, Entergy Arkansas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Arkansas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy Arkansas’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Arkansas pays distributions from its earnings at a percentage determined monthly.

Ironwood Power Station

In November 2024, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Ironwood Power Station (formerly Lake Catherine Unit 5), a 446 MW simple cycle natural gas combustion turbine facility to be located at the existing Lake Catherine facility site in Hot Spring County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. In December 2024 other parties, including the APSC general staff, filed testimony opposing the resource, although the APSC general staff recognized the capacity need for the resource. Entergy Arkansas filed testimony in January 2025 further supporting its application, and in February 2025 the opposing parties filed responsive rebuttal testimony continuing to dispute the estimated costs and to dispute that Entergy Arkansas performed a market solicitation sufficient to demonstrate that this resource is the most reasonable option for customers. Also in February 2025, Entergy Arkansas filed surrebuttal testimony responding to the opposing parties’ testimony. A hearing was held in March 2025, and in April 2025 the APSC issued an order approving certification of the facility. The order also provided a presumption of prudence finding with respect to a benchmark project cost. In May 2025,

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy Arkansas filed a motion for clarification concerning the appropriate calculation of the benchmark that was below the estimated cost of Ironwood Power Station and was based upon older technology and dated pricing. Entergy Arkansas will have the opportunity to present later all actual costs to the APSC for review and a prudence determination of final costs, including costs incremental to the benchmark. In June 2025, Entergy Arkansas filed its independent monitor proposal with the APSC and is awaiting direction on the proposal and the motion for clarification. Entergy Arkansas proposes to recover the costs of constructing Ironwood Power Station through the Generating Arkansas Jobs Act rider. The facility is expected to be in service by the end of 2028. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Generating Arkansas Jobs Act Rider” below for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Jefferson Power Station

In August 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of Jefferson Power Station, an approximately 754 MW natural gas-fired combined cycle combustion turbine facility to be located in Jefferson County, Arkansas. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The estimated cost of the project is $1,602 million. In September 2025 other parties, including the APSC general staff, filed testimony opposing the resource pending further information, although the APSC general staff recognized the capacity need for the resource and that Entergy Arkansas had satisfied the statutory requirements for a certificate of environmental compatibility and public need. Much of the opposition focused on the fact that the resource was not identified through a competitive solicitation. Entergy Arkansas filed testimony further supporting its application in September and October 2025. A hearing was held in October 2025 and November 2025. In January 2026 the APSC issued its order finding that Entergy Arkansas had demonstrated a need for the resource but had not met its burden with respect to supporting the prudence of the costs to construct the resource. The APSC acknowledged that the costs would be greater if Entergy Arkansas waited to pursue the resource. The APSC authorized Entergy Arkansas to proceed with Jefferson Power Station as a strategic investment with estimated costs set at a benchmark, which the APSC erroneously believed reflected the current cost estimate but is, in fact, $90 million below the cost presented. Entergy Arkansas is evaluating whether to make a request for rehearing to correct the benchmark. Additionally, the APSC found that Entergy Arkansas should conduct all-source competitive solicitations moving forward with a limited exception for certain resources associated with customer growth projects. Entergy Arkansas proposes to recover the costs of constructing Jefferson Power Station through the Generating Arkansas Jobs Act rider. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2029. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Generating Arkansas Jobs Act Rider” below for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Special Rate Contract and Arkansas Cypress Solar

In September 2025, Entergy Arkansas filed an application with the APSC seeking approval of a long-term special rate contract between Altitude, LLC, a subsidiary of Alphabet, Inc. (Google) and Entergy Arkansas for the sale of electricity to a new large-scale data center in West Memphis, Arkansas. In October 2025 the APSC general staff filed testimony finding that based on its evaluation of Entergy Arkansas’s application and the results of the ratepayer impact measure test, the special rate contract meets the requirements of the APSC’s promotional practice rules and is in the public interest. No other parties filed testimony. In December 2025 the APSC issued an order approving the special rate contract but denying the requested ratemaking treatment of Google’s upfront payments and deferring a decision on the treatment under the contract pricing providing for the deferral and amortization of the investment tax credits from the Arkansas Cypress Solar facility (discussed below). Also in December 2025, Entergy Arkansas filed a petition with the APSC regarding these findings, noting that they would require renegotiation of the special rate contract. In January 2026 the APSC issued an order maintaining its position on the ratemaking treatment of Google’s upfront payments but reversing itself on the treatment of the Arkansas Cypress

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Solar facility investment tax credits and allowing those to be used in the pricing of the Arkansas Cypress Solar facility to Google as provided for in the contract.

In September 2025, Entergy Arkansas filed an application with the APSC seeking a certificate of environmental compatibility and public need for the construction and operation of the Arkansas Cypress Solar facility, a planned 600 MW solar photovoltaic array with a 350 MW battery energy storage system and associated transmission facilities interconnecting at Entergy Arkansas’s White Bluff substation. The estimated cost of the project is $1,602 million. Entergy Arkansas is seeking public interest and prudence findings from the APSC no later than 180 days from the filing, pursuant to Act 373 of 2025, to construct the Arkansas Cypress Solar facility in support of its long-term special rate contract with Google. In October 2025 the APSC general staff and the Arkansas Attorney General filed responsive testimony opposing the project cost and seeking additional information. Subsequently, the APSC general staff submitted supplemental testimony to update its initial conclusion and recommendations, noting that the Arkansas Cypress Solar facility is a reasonable project and recommending the APSC approve the project under certain conditions. Entergy Arkansas proposes to recover the costs of constructing the Arkansas Cypress Solar facility through the Generating Arkansas Jobs Act rider. A hearing was held in December 2025, and an APSC decision is due in March 2026. Subject to receipt of required regulatory approval and other conditions, the facility is expected to be in service by the end of 2028. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Generating Arkansas Jobs Act Rider” below for discussion of the Generating Jobs Act rider, which was approved by the APSC in October 2025.

Sources of Capital

Entergy Arkansas’s sources to meet its capital requirements include:

internally generated funds;
cash on hand;
the Entergy system money pool;
debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
capital contributions; and
bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Arkansas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy Arkansas require prior regulatory approval. Debt issuances are also subject to requirements 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 (payables to) the money pool were as follows as of December 31 for each of the following years.


2025	2024	2023	2022
(In Thousands)
$21,715	($15,190)	($145,385)	($180,795)

See Note 4 to the financial statements for a description of the money pool.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy Arkansas has a credit facility in the amount of $300 million scheduled to expire in June 2030. Entergy Arkansas also has a $25 million credit facility scheduled to expire in April 2026. The $300 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, 2025, there were no cash borrowings under either credit facility and no letters of credit outstanding under the $300 million credit facility. In addition, Entergy Arkansas is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO. As of December 31, 2025, $93.3 million in letters of credit were outstanding under Entergy Arkansas’s uncommitted letter of credit facilities. 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 2027. As of December 31, 2025, there were $13.7 million in loans outstanding under the credit facility for the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Arkansas obtained authorization from the FERC through February 2028 for the following:

short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding;
long-term borrowings and securities issuances; 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. In addition, the APSC has concurrent jurisdiction over Entergy Arkansas’s first mortgage bond/secured issuances. Entergy Arkansas has obtained first mortgage bond/secured financing authorization from the APSC that extends through December 2027.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Arkansas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Arkansas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the APSC, is primarily responsible for approval of the rates charged to customers.

Retail Rates

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 was $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 report 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. 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 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

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

over a 10-year period as well as recovery of $34.9 million related to the 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.

2024 Formula Rate Plan Filing

In July 2024, Entergy Arkansas filed with the APSC its 2024 formula rate plan filing to set its formula rate for the 2025 calendar year. The filing contained an evaluation of Entergy Arkansas’s earnings for the 2025 projected year and a netting adjustment for the 2023 historical year. The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2025 projected year was 8.43% resulting in a revenue deficiency of $69.5 million. The earned rate of return on common equity for the 2023 historical year was 7.48% resulting in a $33.1 million netting adjustment. The total proposed revenue change for the 2025 projected year and 2023 historical year netting adjustment was $102.6 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 $82.6 million. The APSC general staff and intervenors filed their errors and objections report in October 2024, proposing certain adjustments, including the APSC general staff’s update to annual filing year revenues that increases the constraint to $83.5 million. Entergy Arkansas filed its rebuttal in October 2024, and later in October 2024 the parties submitted a joint issues list and stipulations setting forth the disputed issues and the noncontested issues. In December 2024 the APSC approved the parties’ stipulations without modification, approved Entergy Arkansas’s adjustment with respect to storm costs, directed Entergy Arkansas to adjust its projected year distribution reliability capital closings, and deferred the recoverability of Entergy Arkansas’s opportunity sales legal fees until the next general rate case. Also in December 2024 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2025. As a result of the proceeding, the total revenue change was $82.7 million, including a $63.7 million increase for the 2025 projected year and a $31.4 million netting adjustment for the 2023 historical year. In fourth quarter 2024, Entergy Arkansas recorded a regulatory asset of $15.5 million to reflect the amount of the 2023 historical year netting adjustment that it collected from its customers during the 2025 rate effective period. Pursuant to the terms of the parties’ stipulations, Entergy Arkansas made a filing with the APSC in January 2025 to refund customers $30.1 million in excess accumulated deferred income taxes resulting from the reduction in the State of Arkansas’s income tax rate from 4.8% to 4.3% in 2024. Entergy Arkansas began refunding this amount over a 24-month period effective with the first billing cycle of February 2025.

2025 Formula Rate Plan Filing

In July 2025, Entergy Arkansas filed with the APSC its 2025 formula rate plan filing to set its formula rate for the 2026 calendar year.  The filing contained an evaluation of Entergy Arkansas’s earnings for the 2026 projected year and a netting adjustment for the 2024 historical year.  The filing showed that Entergy Arkansas’s earned rate of return on common equity for the 2026 projected year was 8.45% resulting in a revenue deficiency of $68.9 million.  The earned rate of return on common equity for the 2024 historical year was 7.71% resulting in a $48.8 million netting adjustment.  The total proposed revenue change for the 2026 projected year and 2024 historical year netting adjustment was $117.7 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 $92.3 million. The APSC general staff filed their errors and objections report in October 2025, proposing an adjustment to the coupon rate for the projected long-term debt issuance in 2026 and an update to annual filing year revenues that increases the constraint to $93.9 million. Entergy Arkansas filed its rebuttal in October 2025. A hearing was scheduled for November 2025, and an order was expected in December 2025. Due to no contested

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

issues remaining outstanding among the parties to the proceeding, in October 2025, Entergy Arkansas and the APSC general staff filed a joint motion requesting the APSC cancel the hearing and issue a decision based on the pleadings and testimony in the record. The APSC granted this request. In December 2025 the APSC approved Entergy Arkansas’s request as modified by the APSC general staff’s errors and objections report and Entergy Arkansas’s rebuttal testimony. Also in December 2025 the APSC approved Entergy Arkansas’s compliance tariff effective with the first billing cycle of January 2026. As a result of the proceeding, the total revenue change was $93.9 million, including a $65.6 million increase for the 2026 projected year and a $48.8 million netting adjustment for the 2024 historical year. In fourth quarter 2025, Entergy Arkansas recorded a regulatory asset of $28.3 million to reflect the amount of the 2024 historical year netting adjustment that it expects to collect from its customers during the 2026 rate effective period.

Grand Gulf Credit Rider

In June 2024, Entergy Arkansas filed with the APSC a tariff to provide retail customers a credit resulting from the terms of the settlement agreement between Entergy Arkansas, System Energy, additional named Entergy parties, and the APSC pertaining to System Energy’s billings for wholesale sales of energy and capacity from the Grand Gulf nuclear plant. See “Complaints Against System Energy - System Energy Settlement with the APSC” in Note 2 to the financial statements for discussion of the System Energy settlement with the APSC. In July 2024 the APSC approved the tariff, under which Entergy Arkansas would refund to retail customers a total of $100.6 million. Entergy Arkansas refunded $92.3 million of the total through one-time bill credits under the Grand Gulf credit rider during the August 2024 billing cycle. In March 2025, Entergy Arkansas included the remaining balance as a credit to retail customers in its energy cost recovery rider rate redetermination filing. See further discussion within “Energy Cost Recovery Rider” below. In April 2025 the APSC approved Entergy Arkansas’s proposal to include the remaining balance in its energy cost recovery rider effective with the first billing cycle of April 2025 and the withdrawal of the Grand Gulf credit rider after all credits had been issued. Credits to retail customers were completed in second quarter 2025, and the Grand Gulf credit rider was subsequently withdrawn.

Generating Arkansas Jobs Act Rider

In March 2025 the State of Arkansas passed the Generating Arkansas Jobs Act of 2025, now Act 373 (Act 373), that authorizes the recovery of financing costs during construction of generation and transmission investments through a rider separate from the formula rate plan. Act 373 also permits cost recovery of those investments, when completed and in service, either through the next general rate case proceeding or under the formula rate plan. Act 373 streamlines and simplifies the regulatory approval process and provides increased timeliness and certainty of cost recovery.

In July 2025, Entergy Arkansas submitted a tariff filing with the APSC requesting approval of a strategic investment recovery rider, consistent with the provisions of Act 373. In October 2025 the APSC issued an order approving the proposed rider with several revisions, including elimination of an annual true-up adjustment, a change in cost allocation methodology, the removal of excess and deficient accumulated deferred income taxes to a separate rider, and the addition of reporting requirements. As directed by the order, in October 2025, Entergy Arkansas made a compliance filing. In November 2025, the APSC general staff recommended additional updates to the compliance filing, including limiting the accumulated deferred income tax adjustment to excess accumulated deferred income taxes. Also, in November 2025, Entergy Arkansas filed a second compliance filing, which was approved by the APSC.

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

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

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 the “ANO Damage, Outage, and NRC Reviews” section 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 rate from $0.01164 per kWh to $0.01547 per kWh. The APSC staff filed testimony in March 2017 recommending that the redetermined rate be implemented with the first billing cycle of April 2017 under the normal operation of the tariff. Accordingly, the redetermined rate went into effect on March 31, 2017 pursuant to the tariff. In July 2017 the Arkansas Attorney General requested additional information to support certain of the costs included in Entergy Arkansas’s 2017 energy cost rate redetermination.

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

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

of Entergy Arkansas’s energy cost recovery rider. In late-2018 the APSC general staff notified Entergy Arkansas it initiated an audit of the 2017 fuel costs. The timing of the audit’s completion is uncertain at this time.

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 in the rate from $0.01639 per kWh to $0.01883 per kWh. The primary reason for the rate increase was a large under-recovered balance as a result of higher natural gas prices in 2022 and a $32 million deferral related to the APSC general staff’s request in 2022 for Entergy Arkansas to defer its request for recovery related to the February 2021 winter storms until the 2023 energy cost rate redetermination. In February 2023 the APSC issued orders initiating proceedings to address the prudence of costs incurred and appropriate cost allocation of the February 2021 winter storms, and in September 2023 the APSC issued an order finding Entergy Arkansas’s practices during the February 2021 winter storms to be prudent. The under-recovered balance included in the March 2023 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.

In March 2024, Entergy Arkansas filed its annual redetermination of its energy cost rate pursuant to the energy cost recovery rider, which reflected a decrease in the rate from $0.01883 per kWh to $0.00882 per kWh. Due to a change in law in the State of Arkansas, the annual redetermination included $9 million, recorded as a credit to fuel expense in first quarter 2024, for recovery attributed to net metering costs in 2023. The primary reason for the rate decrease was a large over-recovered balance as a result of lower natural gas prices in 2023. To mitigate the effect of projected increases in natural gas prices in 2024, Entergy Arkansas adjusted the over-recovered balance included in the March 2024 annual redetermination filing by $43.7 million. This adjustment reduced the rate change that was reflected in the 2025 energy cost rate redetermination. The redetermined rate of $0.00882 per kWh became effective with the first billing cycle in April 2024 through the normal operation of the tariff.

In March 2025, 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 $0.00882 per kWh to $0.01333 per kWh. The annual redetermination included a credit related to the remaining balance due to retail customers from the System Energy settlement with the APSC, plus carrying charges and interest. See “Retail Rates - Grand Gulf Credit Rider” above for further discussion. The primary reason for the rate increase was an adjustment to account for projected increases in natural gas prices in 2025. This adjustment is expected to reduce the rate change that will be reflected in Entergy Arkansas’s 2026 energy cost rate redetermination. The redetermined rate of $0.01333 per kWh became effective with the first billing cycle in April 2025 through the normal operation of the tariff.

Opportunity Sales Proceeding

In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocated the energy generated by Entergy System resources; (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity; and (c) violated the provision of the System Agreement that prohibited sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenged sales made beginning in 2002 and requested refunds. In July 2009 the Utility operating companies filed a response to the complaint arguing among other things that the System Agreement contemplated 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.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The FERC issued a decision in June 2012 and held that, while the System Agreement was ambiguous, it did 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 did 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.

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.

The hearing required by the FERC’s second 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.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

In December 2018, Entergy made a compliance filing in response to the FERC’s October 2018 order. The compliance filing provided a final calculation of Entergy Arkansas’s payments to the other Utility operating companies, including interest. Refunds and interest, totaling $135 million, were paid by Entergy Arkansas to the other operating companies in December 2018.

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.

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 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. 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. The refunds were issued in the August 2020 billing cycle. Entergy Arkansas believed its actions were prudent and, therefore, the costs, including the $13.7 million, plus interest, were recoverable, and 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 March 2024 the U.S. District Court for the Eastern District of Arkansas issued a judgment in favor of the APSC and against Entergy Arkansas. In March 2024 Entergy Arkansas filed a notice of appeal and a motion to expedite oral arguments with the United States Court of Appeals for the Eighth Circuit and the court granted the motion to expedite. Briefing to the United States Court of Appeals for the Eighth Circuit concluded in July 2024 and oral arguments concluded in September 2024. As a result of the adverse decision by the U.S. District Court for the Eastern District of Arkansas, Entergy Arkansas concluded that it could no longer support the recognition of its $131.8 million regulatory asset reflecting the previously-expected recovery of a portion of the costs at issue in the opportunity sales proceeding and recorded a $131.8 million ($99.1 million net-of-tax) charge to earnings in first quarter 2024. In December 2024 the United States Court of Appeals for the Eighth Circuit affirmed the decision of the U.S. District Court for the Eastern District of Arkansas, and Entergy Arkansas filed a petition for rehearing en banc. In January 2025 the United States Court of Appeals for the Eighth Circuit denied Entergy Arkansas’s petition. In April 2025, Entergy Arkansas filed a petition for certiorari with the United States Supreme Court. In June 2025 the United States Supreme Court denied Entergy Arkansas’s petition for certiorari.

Net Metering Legislation

After the passage of an Arkansas net metering law that was enacted effective July 2019, the APSC 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 allowed the aggregation of accounts by net metering customers. These decisions by the APSC created subsidies in favor of

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

eligible net metering customers to the detriment of non-participating customers. The level of this subsidy grew as additional net metering applications were approved by the APSC. The size and number of customers eligible under the 2019 law present a risk of loss of load and shifting of costs to customers.

Another Arkansas law was enacted effective March 2023 that revised 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. As of October 2024, new net metering facilities are subject to two-channel billing. Because of the new law, in May 2023, the APSC closed its prior cost-shifting proceeding and grandfathering rulemaking relating to the prior net metering rate structure. Under the new law, the APSC had to approve revisions to utilities’ net metering 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.

Industrial and Commercial Customers

Entergy Arkansas’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Arkansas responds by working with industrial and commercial customers to negotiate electric service contracts with competitive rates that match specific customer needs and load profiles. Additionally, cogeneration is an option available to a portion of Entergy Arkansas’s industrial customer base. Entergy Arkansas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

Entergy 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 acquisition, 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. In November 2025, Entergy Arkansas notified the NRC of its intent to submit applications to further extend the operating licenses for ANO 1 and 2. Entergy Arkansas expects to submit the renewal applications for ANO 1 by the end of fourth quarter 2029 and for ANO 2 by the end of fourth quarter 2033.

Entergy Arkansas, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

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 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.

Entergy Arkansas, 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 2026 Qualified Pension Cost	Impact on 2025 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$652	$22,948
Rate of return on plan assets	(0.25%)	$2,718	$—
Rate of increase in compensation	0.25%	$921	$4,688

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 2026 Postretirement Benefits Cost	Impact on 2025 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$315	$3,790
Health care cost trend	0.25%	$383	$2,094

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 2025 was $20.9 million, including $1.5 million in settlement costs. Entergy Arkansas anticipates 2026 qualified pension cost to be $16.5 million. Entergy Arkansas contributed $35.5 million to its qualified pension plans in 2025 and estimates pension contributions will be approximately $29.7 million in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026.

Total postretirement health care and life insurance benefit income for Entergy Arkansas in 2025 was $6.8 million. Entergy Arkansas expects 2026 postretirement health care and life insurance benefit income of approximately $9.4 million. Entergy Arkansas contributed $1.1 million to its other postretirement plans in 2025 and estimates that 2026 contributions will be approximately $710 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, 2025 and 2024, the related consolidated statements of income, cash flows and changes in equity (pages 348 through 352 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, 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 the likelihood of 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 refund 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 19, 2026

We have served as the Company’s auditor since 2001.


ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING REVENUES
Electric	$2,784,047	$2,460,181	$2,646,396

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	352,535	274,282	514,885
Purchased power	248,901	239,281	257,890
Nuclear refueling outage expenses	43,177	51,840	59,973
Other operation and maintenance	778,445	742,573	737,649
Asset write-offs	—	131,775	78,434
Decommissioning	100,701	93,582	87,321
Taxes other than income taxes	164,045	141,225	141,502
Depreciation and amortization	463,802	422,767	400,944
Other regulatory charges (credits) - net	(62,186)	(152,834)	(87,409)
TOTAL	2,089,420	1,944,491	2,191,189

OPERATING INCOME	694,627	515,690	455,207

OTHER INCOME
Allowance for equity funds used during construction	24,349	29,569	20,587
Interest and investment income	67,375	70,628	25,024
Miscellaneous - net	(10,536)	(17,995)	(23,216)
TOTAL	81,188	82,202	22,395

INTEREST EXPENSE
Interest expense	242,216	218,281	188,232
Allowance for borrowed funds used during construction	(11,734)	(14,429)	(8,270)
TOTAL	230,482	203,852	179,962

INCOME BEFORE INCOME TAXES	545,333	394,040	297,640

Income taxes	107,880	74,574	(99,210)

NET INCOME	437,453	319,466	396,850

Net loss attributable to noncontrolling interest	(3,079)	(5,300)	(5,231)

EARNINGS APPLICABLE TO MEMBER'S EQUITY	$440,532	$324,766	$402,081

See Notes to Financial Statements.


ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING ACTIVITIES
Net income	$437,453	$319,466	$396,850
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	650,881	588,599	556,780
Deferred income taxes, tax credits, and non-current taxes accrued	341,658	81,911	(102,070)
Asset write-offs	—	131,775	78,434
Changes in assets and liabilities:
Receivables	(30,391)	114,936	(84,428)
Fuel inventory	10,555	7,558	(6,351)
Accounts payable	36,401	(10,425)	(69,947)
Taxes accrued	21,778	(11,936)	4,625
Interest accrued	1,332	3,007	16,554
Deferred fuel costs	(72,862)	(43,124)	228,021
Other working capital accounts	(46,046)	(29,148)	(29,690)
Provisions for estimated losses	9,060	17,520	(21,039)
Regulatory assets	(43,738)	185,251	(6,197)
Other regulatory liabilities	218,074	97,049	240,762
Customer advances	10,000	—	—
Pension and other postretirement funded status	(79,244)	(135,464)	(109,077)
Other assets and liabilities	(129,863)	(338,295)	(152,206)
Net cash flow provided by operating activities	1,335,048	978,680	941,021
INVESTING ACTIVITIES
Construction expenditures	(1,046,878)	(812,329)	(946,244)
Allowance for equity funds used during construction	24,349	29,569	20,587
Payment for purchase of plant and assets	(3,517)	(819,014)	—
Nuclear fuel purchases	(120,819)	(151,604)	(137,616)
Proceeds from sale of nuclear fuel	40,601	33,213	32,937
Proceeds from nuclear decommissioning trust fund sales	169,591	718,415	117,123
Investment in nuclear decommissioning trust funds	(202,872)	(730,910)	(139,280)
Change in money pool receivable - net	(21,715)	—	—
Litigation proceeds for reimbursement of spent nuclear fuel storage costs	—	—	17,933
Decrease (increase) in other investments	(36,977)	30	1,608
Other	1,115	—	—
Net cash flow used in investing activities	(1,197,122)	(1,732,630)	(1,032,952)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	439,709	1,154,129	1,093,253
Retirement of long-term debt	(149,422)	(717,121)	(597,720)
Capital contributions from parent	—	695,000	—

Changes in money pool payable - net	(15,190)	(130,195)	(35,410)
Common equity distributions paid	(190,000)	(310,000)	(417,000)
Other	47,800	63,252	47,162
Net cash flow provided by financing activities	132,897	755,065	90,285
Net increase (decrease) in cash and cash equivalents	270,823	1,115	(1,646)
Cash and cash equivalents at beginning of period	4,747	3,632	5,278
Cash and cash equivalents at end of period	$275,570	$4,747	$3,632

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$213,561	$212,691	$169,173
Income taxes - net (includes production tax credit sale proceeds of $215,224 in 2025, $— in 2024, and $— in 2023)	($244,911)	$9,484	$2,705
Noncash investing activities:
Accrued construction expenditures	$98,219	$37,495	$36,264

See Notes to Financial Statements.


ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2025	2024
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$7,048	$1,306
Temporary cash investments	268,522	3,441
Total cash and cash equivalents	275,570	4,747
Accounts receivable:
Customer	164,296	139,234
Allowance for doubtful accounts	(7,303)	(4,672)
Associated companies	43,859	35,412
Other	87,029	70,927
Accrued unbilled revenues	130,950	125,824
Total accounts receivable	418,831	366,725
Deferred fuel costs	27,704	—
Fuel inventory - at average cost	39,382	49,937
Materials and supplies	430,662	384,238
Deferred nuclear refueling outage costs	36,718	48,879
Prepayments and other	98,975	41,404
TOTAL	1,327,842	895,930

OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds	1,816,331	1,604,428
Other	793	797
TOTAL	1,817,124	1,605,225

UTILITY PLANT
Electric	17,022,476	16,371,182
Construction work in progress	621,218	320,447
Nuclear fuel	302,706	257,533
TOTAL UTILITY PLANT	17,946,400	16,949,162
Less - accumulated depreciation and amortization	6,585,693	6,275,150
UTILITY PLANT - NET	11,360,707	10,674,012

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets	1,743,848	1,700,110

Other	221,381	198,706
TOTAL	1,965,229	1,898,816

TOTAL ASSETS	$16,470,902	$15,073,983

See Notes to Financial Statements.


ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2025	2024
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$690,000	$—
Accounts payable:
Associated companies	103,411	85,137
Other	346,541	210,040
Customer deposits	136,587	129,267
Taxes accrued	114,993	93,215
Interest accrued	39,709	38,377
Deferred fuel costs	—	45,158
Other	56,083	55,313
TOTAL	1,487,324	656,507

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	1,846,713	1,489,169
Accumulated deferred investment tax credits	24,868	26,069
Regulatory liability for income taxes - net	422,740	417,561
Other regulatory liabilities	1,044,060	831,165
Customer advances	10,000	—
Decommissioning	1,791,372	1,691,583
Accumulated provisions	85,539	76,479

Long-term debt	4,733,604	5,122,494
Other	314,495	298,951
TOTAL	10,273,391	9,953,471

Commitments and Contingencies

EQUITY
Member's equity	4,699,369	4,448,837
Noncontrolling interest	10,818	15,168
TOTAL	4,710,187	4,464,005

TOTAL LIABILITIES AND EQUITY	$16,470,902	$15,073,983

See Notes to Financial Statements.


ENTERGY ARKANSAS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2025, 2024, and 2023

	Noncontrolling Interest	Member's Equity	Total
	(In Thousands)

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
Net income (loss)	(5,300)	324,766	319,466
Capital contributions from parent	—	695,000	695,000
Common equity distributions	—	(310,000)	(310,000)
Distributions to noncontrolling interest	(1,131)	—	(1,131)
Balance at December 31, 2024	$15,168	$4,448,837	$4,464,005
Net income (loss)	(3,079)	440,532	437,453

Common equity distributions	—	(190,000)	(190,000)
Distributions to noncontrolling interest	(1,271)	—	(1,271)
Balance at December 31, 2025	$10,818	$4,699,369	$4,710,187

See Notes to Financial Statements.

ENTERGY LOUISIANA, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Winter Storm Fern

See the “Winter Storm Fern” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Winter Storm Fern. Entergy Louisiana’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $240 million to $300 million, with the majority of the costs being capital. Natural gas purchases for Entergy Louisiana for January 2026 are $256 million compared to natural gas purchases for January 2025 of $115 million.

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $222.1 million primarily due to expenses of $151.5 million ($110.7 million net-of-tax), recorded in second quarter 2024, primarily consisting of regulatory charges to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023. Also contributing to the increase was higher other income, higher volume/weather, and a higher return on construction work in progress for certain utility plant investments. The increase was partially offset by higher interest expense, higher other operation and maintenance expenses, and higher depreciation and amortization expenses. See Note 2 to the financial statements for discussion of the agreement in principle and the subsequently filed global stipulated settlement agreement.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:


			Amount
			(In Millions)
2024 operating revenues			$5,144.0
Fuel, rider, and other revenues that do not significantly affect net income			576.1
Volume/weather			31.8
Return on construction work in progress for certain utility plant investments			28.3
Retail electric price			(16.7)
Effect of sale of natural gas distribution business			(31.4)
2025 operating revenues			$5,732.1

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.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The volume/weather variance is primarily due to an increase in industrial usage resulting from an increase in demand from large industrial customers, primarily in the petroleum refining, chlor-alkali, industrial gases, and petrochemicals industries.

The return on construction work in progress for certain utility plant investments variance represents the revenue related to the amortization of certain customer advances designed to provide a return on investment in construction work in progress for certain utility plant investment, which is recognized as the related costs are incurred.

The retail electric price variance is primarily due to a decrease in Entergy Louisiana's formula rate plan revenues for a two month period beginning in September 2025, resulting from earnings above the authorized return on common equity for the 2024 test year. The decrease was partially offset by increases in Entergy Louisiana’s formula rate plan revenues, including an increase in the distribution recovery mechanism, effective September 2024. See Note 2 to the financial statements for discussion of the formula rate plan proceedings.

The effect of sale of natural gas distribution business variance represents the decrease in operating revenues resulting from the absence of natural gas revenues following the sale of the natural gas distribution business on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025.

Total electric energy sales for Entergy Louisiana for the years ended December 31, 2025 and 2024 are as follows:


	2025	2024	% Change
	(GWh)
Residential	14,251	14,000	2
Commercial	11,134	11,108	—
Industrial	35,816	34,759	3
Governmental	802	836	(4)
Total retail	62,003	60,703	2
Sales for resale:
Associated companies	6,477	5,808	12
Non-associated companies	1,388	1,574	(12)
Total	69,868	68,085	3

See Note 19 to the financial statements for additional discussion of Entergy Louisiana’s operating revenues.

Other Income Statement Variances

Nuclear refueling outage expenses decreased primarily due to the amortization of lower costs associated with the most recent outages as compared to previous outages.

Other operation and maintenance expenses increased primarily due to:

an increase of $19.7 million in power delivery expenses primarily due to a higher scope of work performed in 2025 as compared to 2024 and higher vegetation maintenance costs;
the expensing of $10.8 million of project costs associated with the Bayou Power Station project following Entergy Louisiana’s election in 2025 to cancel the project and evaluate an alternative transmission solution. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources” below for discussion of the Bayou Power Station project;

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

an increase of $10.1 million in bad debt expense;
an increase of $7.7 million in non-nuclear generation expenses primarily due to a higher scope of work performed during plant outages in 2025 as compared to 2024;
an increase of $5.6 million in transmission costs allocated by MISO. See Note 2 to the financial statements for discussion of the recovery of these costs;
an increase of $5.1 million in loss provisions; and
several individually insignificant items.

The increase was partially offset by:

an $18.6 million gain, recorded in 2025, resulting from the sale of the natural gas distribution business on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025;
contract costs of $17.4 million in 2024 related to operational performance, customer service, and organizational health initiatives; and
a decrease of $13.3 million in nuclear generation expenses primarily due to a lower scope of work performed in 2025 as compared to 2024.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments.

Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in nuclear depreciation rates effective September 2024 and September 2025 in accordance with the global stipulated settlement agreement approved by the LPSC in August 2024. See Note 2 to the financial statements for discussion of the global stipulated settlement agreement.

Other regulatory charges (credits) - net includes regulatory charges of $150.2 million, recorded in second quarter 2024, to reflect the effects of an agreement in principle between Entergy Louisiana and the LPSC staff and the intervenors in July 2024 to renew Entergy Louisiana’s formula rate plan and resolve a number of other retail dockets and matters, including all formula rate plan test years prior to 2023. The customer rate credits agreed to in the global stipulated settlement began in September 2024. 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. See Note 2 to the financial statements for discussion of the agreement in principle and the subsequently filed global stipulated settlement agreement.

Other income increased primarily due to:

an increase of $43.3 million in the amortization of tax gross ups on customer advances, including customer advances for construction;
an increase of $25.8 million in 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 2025; and
a $17.1 million true-up of Entergy Louisiana's MISO cost recovery mechanism over-recovery balance to the 2024 formula rate plan filing, which was filed with the LPSC in May 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.

The increase was partially offset by a decrease of $17.5 million in affiliated dividend income from affiliated preferred membership interests related to storm cost securitizations. See Note 2 to the financial statements for discussion of the storm cost securitizations.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Interest expense increased primarily due to the issuance of $750 million of 5.80% Series mortgage bonds in January 2025, the issuance of $700 million of 5.15% Series mortgage bonds in August 2024, and an increase of $38.4 million in carrying costs on customer advances, including customer advances for construction. The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2025.

The effective income tax rates were 17.6% for 2025 and 20.2% for 2024. 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.

2024 Compared to 2023

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, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.

Income Tax Legislation and Regulation

Sale of Natural Gas Distribution Business

See the “Dispositions - Natural Gas Distribution Businesses” section in Note 14 to the financial statements for discussion of the sale of the Entergy Louisiana natural gas distribution business.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:


	2025	2024	2023
	(In Thousands)
Cash and cash equivalents at beginning of period	$327,102	$2,772	$56,613

Net cash provided by (used in):
Operating activities	2,741,721	2,247,563	2,032,120
Investing activities	(2,877,549)	(1,512,147)	(3,039,456)
Financing activities	585,687	(411,086)	953,495
Net increase (decrease) in cash and cash equivalents	449,859	324,330	(53,841)

Cash and cash equivalents at end of period	$776,961	$327,102	$2,772

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $494.2 million in 2025 primarily due to:

higher collections from customers;
an increase of $257.7 million in receipts from advance payments related to customer agreements in 2025, which are recorded as current liabilities and included within changes in other working capital accounts;
net cash proceeds of $170.1 million received by Entergy Louisiana in 2025, including $198.3 million in proceeds received from Entergy Louisiana’s transfer of 2024 nuclear production tax credits to third parties in 2025 and net cash payments of $28.2 million to affiliates in 2025 in accordance with the Unit Power Sales Agreement and the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by Entergy Louisiana and affiliates to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits;
income tax refunds of $146 million in 2025 compared to income tax payments of $16.9 million in 2024. Entergy Louisiana received income tax refunds in 2025 and made income tax payments in 2024, each in accordance with Entergy’s tax allocation agreement; and
a decrease of $18.4 million in storm spending primarily due to Hurricane Francine restoration efforts in 2024.

The increase was partially offset by:

the timing of payments to vendors;
the receipt of $80.2 million in settlement proceeds in December 2024 as a result of the System Energy settlement with the LPSC. See Note 2 to the financial statements for discussion of the System Energy settlement agreement with the LPSC;
an increase of $47.2 million in interest paid;
an increase of $24.5 million in spending on nuclear refueling outages in 2025 as compared to 2024;
$21.3 million received in third quarter 2024 related to the wind up of the NISCO partnership. See Note 9 to the financial statements for a discussion of the NISCO partnership; and
higher fuel and purchased power payments. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.

Investing Activities

Net cash flow used in investing activities increased $1,365.4 million in 2025 primarily due to:

an increase of $661.5 million in non-nuclear generation construction expenditures primarily due to higher spending on the Franklin Farms Power Station Units 1 and 2 project, the Waterford 5 Power Station project, and the Sterlington facility project;
an increase of $347 million in transmission construction expenditures primarily due to higher capital expenditures as a result of increased development in Entergy Louisiana’s service area, including increased investment in the resilience of the transmission system, higher spending on the Amite South transmission projects, and increased spending on various other transmission projects in 2025;
an increase of $286 million in distribution construction expenditures primarily due to increased investment in the resilience of the distribution system, partially offset by lower capital expenditures for storm restoration in 2025. The decrease in storm restoration expenditures is primarily due to decreased spending on Hurricane Francine restoration efforts in 2025 as compared to 2024;
an increase of $126.9 million in nuclear construction expenditures primarily due to increased spending on various nuclear projects in 2025;

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

an increase in cash used of $80.8 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;
cash collateral of $58.4 million posted in 2025 to support Entergy Louisiana’s obligations to MISO; and
payments totaling $41.4 million to Entergy Texas for the transfer of assets related to the Segno Solar and Votaw Solar facilities to Entergy Louisiana in 2025. See “Uses and Sources of Capital - Segno Solar and Votaw Solar” below for further discussion of the facilities and transfer.

The increase was partially offset by the receipt of $200 million in proceeds from the sale of the natural gas distribution business on July 1, 2025 and the receipt of $33.5 million from the storm reserve escrow account in first quarter 2025. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025. See Note 2 to the financial statements for a discussion of the storm reserve funds.

Financing Activities

Entergy Louisiana’s financing activities provided $585.7 million of cash in 2025 as compared to using $411.1 million of cash in 2024 primarily due to the following activity:

the repayment, prior to maturity, of $1 billion of 0.95% Series mortgage bonds in August 2024;
the issuance of $750 million of 5.80% Series mortgage bonds in January 2025;
an increase of $683.9 million in net customer advances for construction related to transmission, distribution, and generator interconnection agreements;
the repayment, prior to maturity, of $400 million of 5.40% Series mortgage bonds in April 2024;
a decrease of $102.9 million in common equity distributions paid in 2025 in order to maintain Entergy Louisiana’s capital structure and for future general corporate purposes;
net long-term borrowings of $56.4 million in 2025 compared to net repayments of $38.5 million in 2024 on the nuclear fuel company variable interest entities’ credit facilities;
the repayment, prior to maturity, of $110 million of 3.78% Series mortgage bonds in March 2025;
the repayment, prior to maturity, of $190 million of 3.78% Series mortgage bonds in March 2025;
the issuance of $700 million of 5.15% Series mortgage bonds in August 2024;
the issuances of $500 million of 5.35% Series mortgage bonds and $700 million of 5.70% Series mortgage bonds in March 2024; and
money pool activity.

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 $156.2 million in 2024. 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 additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Louisiana’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Capital Structure

Entergy Louisiana’s debt to capital ratio is shown in the following table.


	December 31, 2025		December 31, 2024
Debt to capital	46.6	%	46.0	%


Effect of subtracting cash	(2.0	%)	(0.8	%)
Net debt to net capital (non-GAAP)	44.6	%	45.2	%

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 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.

Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.


	2026	2027	2028	2029
	(In Millions)
Planned construction and capital investment:
Generation	$2,550	$4,490	$3,055	$3,300
Transmission	1,670	1,675	1,315	885
Distribution	1,165	830	560	605
Utility Support	90	85	70	70
Total	$5,475	$7,080	$5,000	$4,860

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, expand, and diversify Entergy

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Louisiana’s portfolio, as well as to support customer growth, including Segno Solar, Votaw Solar, Bogalusa West Solar, Cypress Harvest Solar, Franklin Farms Power Station Units 1 and 2, Waterford 5 Power Station, Cottonwood Power Station, Westlake Power Station, and other new generation resources; 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 customer growth and 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, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Louisiana’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Louisiana’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect Entergy Louisiana’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy Louisiana’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.

Entergy Louisiana has incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on its current and planned capital projects. Entergy Louisiana is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments).


	2026	2027	2028	2029-2030	After 2030
	(In Millions)
Long-term debt (a)	$1,134	$1,010	$798	$740	$14,048
Operating leases (b)	$21	$18	$15	$15	$4
Finance leases (b)	$7	$6	$6	$9	$5

(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 $41.6 million to its qualified pension plans and approximately $14.1 million to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026. 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, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy Louisiana has $425.5 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 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 divestiture from the Unit Power Sales Agreement and its obligations under the Vidalia purchased power agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.

Renewables

2021 Solar Certification and the Geaux Green Option

In November 2021, Entergy Louisiana filed an application seeking LPSC approval and certification of the addition of four new solar photovoltaic resources with a combined nameplate capacity of 475 MW (the 2021 Solar Portfolio) and the implementation of a new green tariff, the Geaux Green Option (Rider GGO). The 2021 Solar Portfolio consisted of four resources that were 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 MW resource in St. James Parish; (ii) the Sunlight Road Facility, a 50 MW resource in Washington Parish; (iii) the St. Jacques Facility, a 150 MW resource in St. James Parish; and (iv) the Elizabeth Facility, a 125 MW 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 each achieved commercial operation in 2024, and the Vacherie Facility and the St. Jacques Facility originally had estimated in service dates in 2025. The filing proposed to recover the costs of the power purchase agreements through the fuel adjustment clause and the formula rate plan and the acquisition costs through the formula rate plan.

The proposed Rider GGO was a voluntary rate schedule designed to 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 was also designed to preserve 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. In March 2024 the project developer submitted a

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

solar energy facility farm permit application to the St. James Parish planning commission to request approval for the Vacherie and St. Jacques Facilities. In June 2024 the St. James Parish council denied the application and following this denial, the project developer and one of the project’s ground lessors filed separate lawsuits seeking to overturn the council’s decision. The council’s decision was subsequently affirmed by the Louisiana 23rd Judicial District Court. Entergy Louisiana is no longer pursuing the addition of resources through an acquisition of the St. Jacques Facility or through a power purchase agreement with the Vacherie Facility.

2022 Solar Portfolio and Expansion of the Geaux Green Option

In February 2023, Entergy Louisiana filed an application seeking LPSC approval and 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 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 achieved commercial operation in January 2026.

Bogalusa West Solar

In July 2025, Entergy Louisiana filed an application seeking LPSC approval and certification of the Bogalusa West Solar facility, a 200 MW single axis tracking solar photovoltaic power facility in Washington Parish, Louisiana. In October 2025 the LPSC voted to grant Entergy Louisiana’s application and approve the Bogalusa West Solar facility. The facility is expected to be in service by 2028.

Segno Solar and Votaw Solar

In July 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Segno Solar facility, a 170 MW solar facility to be located in Polk County, Texas, and the Votaw Solar facility, a 141 MW solar facility to be located in Hardin County, Texas. In August 2025, Entergy Texas filed, and the ALJs with the State Office of Administrative Hearings granted, an unopposed motion to withdraw the application. In September 2025, Entergy Texas and Entergy Louisiana entered into assignment and assumption agreements pursuant to which Entergy Texas assigned, and Entergy Louisiana assumed, certain interests in the Segno Solar and Votaw Solar facilities, and the associated assets were transferred in third quarter 2025 from Entergy Texas to Entergy Louisiana for approximately $42.1 million, which included adjustments per the assignment and assumption agreements.

In December 2025, Entergy Louisiana filed an application with the LPSC seeking approval and certification to construct the Segno Solar facility and Votaw Solar facility. The application asks that the LPSC approve, subject to certain ongoing discussions, allocation of the two facilities to a designated renewable resources subscription to Entergy Louisiana’s Rider Geaux Zero, and further asserts that the two solar resources fall below certain breakeven parameters established in connection with the LPSC’s order allowing Entergy Louisiana to procure up to 3 GW of solar resources, thus supporting that the resources should be certified as being in the public interest. The application requests consideration by the LPSC at or before its August 2026 meeting. A procedural schedule has been set with a hearing scheduled for July 2026. The Segno Solar facility and the Votaw Solar facility are expected to be in service by 2029.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Cypress Harvest Solar

In February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification for the Cypress Harvest Solar facility, a 200 MW solar facility to be located in Iberville Parish. Entergy Louisiana requested that the LPSC consider the request at its April 2026 meeting.

Other Generation and Transmission

Bayou Power Station

In March 2024, Entergy Louisiana filed an application seeking LPSC approval and certification that the public convenience and necessity would be served by the construction of the Bayou Power Station, a 112 MW aggregated capacity floating natural gas power station with black-start capability in Leeville, Louisiana and an associated microgrid that would serve nearby areas, including Port Fourchon, Golden Meadow, Leeville, and Grand Isle. In its application, Entergy Louisiana noted that the estimated cost of the Bayou Power Station was $411 million, including estimated costs of transmission interconnection and other related costs. In October 2024, Entergy Louisiana filed a motion to suspend the procedural schedule in this proceeding in order to evaluate certain recent developments related to the project including potential changes to the estimated cost of the project. In October 2025, Entergy Louisiana filed with the LPSC a motion to dismiss its application without prejudice, noting that this project has been canceled and that Entergy Louisiana is evaluating an alternative transmission solution. In November 2025 the LPSC granted the motion and dismissed the application, without prejudice. In third quarter 2025, Entergy Louisiana expensed $10.8 million of project costs related to the Bayou Power Station project.

Additional Generation and Transmission Resources

In October 2024, Entergy Louisiana filed an application with the LPSC seeking approval of a variety of generation and transmission resources proposed in connection with establishing service to a new data center to be developed by a subsidiary of Meta Platforms, Inc. in north Louisiana, for which an electric service agreement has been executed. The filing requested LPSC certification of three new combined cycle combustion turbine generation resources totaling 2,262 MW, each of which will be enabled for future carbon capture and storage, a new 500 kV transmission line, and 500 kV substation upgrades. Two of the new combined cycle combustion turbine generation resources are to be located at Franklin Farms in north Louisiana (Franklin Farms Power Station Units 1 and 2). The application also requested approval to implement a corporate sustainability rider applicable to the new customer. The corporate sustainability rider contemplates the new customer contributing to the costs of the future addition of 1,500 MW of new solar and energy storage resources, agreements involving carbon capture and storage at Entergy Louisiana’s existing Lake Charles Power Station, and potential future wind and nuclear resources. The combined cost of Franklin Farms Power Station Units 1 and 2 is estimated to be approximately $2,387 million. In testimony filed with its application, Entergy Louisiana noted that the third new generation resource, Waterford 5 Power Station, is expected to have an estimated cost similar to the cost of each of Franklin Farms Power Station Units 1 and 2. Also in its testimony, Entergy Louisiana noted that the cost of the new 500 kV transmission line is estimated to be $546 million. Entergy Louisiana anticipates funding the incremental cost to serve the customer through direct financial contributions from the customer and the revenues it expects to earn under the electric service agreement. The electric service agreement also contains provisions for termination payments that will help ensure that there is no harm to Entergy Louisiana and its customers in the event of early termination. A directive was issued at the LPSC’s November 2024 meeting for the matter to be decided by October 2025. In February 2025 intervenors filed a motion asking the LPSC to deny Entergy Louisiana’s requested exemption from the LPSC’s order addressing competitive solicitation procedures and further asking the LPSC to dismiss the application. The ALJ issued an order denying the motion to dismiss the application and deferring the LPSC’s consideration of the motion regarding the competitive solicitation procedures until the hearing. In March 2025 the same intervenors filed a motion requesting the LPSC to require the customer and its parent company to be joined as parties to the proceeding or dismiss the application. In April 2025 the ALJ issued an order denying the March 2025 motion, and the moving parties filed a motion asking the LPSC to review and reverse the ALJ’s decision.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

In February 2025, Entergy Louisiana filed supplemental testimony with the LPSC stating that the third combined cycle combustion turbine resource presented in the October 2024 application (Waterford 5 Power Station) would be sited at Entergy Louisiana’s Waterford site in Killona, Louisiana, alongside existing Entergy Louisiana generation resources. The testimony also notes that Entergy Louisiana is negotiating with the customer in response to the customer’s request to increase the load associated with its project in north Louisiana. The testimony indicates further that the additional load can be served without additional generation capacity beyond what was presented in the October 2024 application, but that additional transmission facilities, which will be funded directly by the customer, are needed to serve this additional load.

In April 2025 and May 2025 the LPSC staff and certain intervenors each filed their direct testimony and cross-answering testimony, respectively. The LPSC staff’s testimony discussed the significant projected benefits associated with the data center project; however, both the LPSC staff and such intervenors also identified purported risks associated with constructing the requested resources based on the terms and conditions under which the customer would be taking service. Both the LPSC staff and such intervenors also recommended that the LPSC impose certain conditions on its approval which, if adopted, would support approval of Entergy Louisiana’s application. The LPSC staff’s recommendations included a condition that would require, under specified circumstances, certain sharing of net revenues from service to the project with Entergy Louisiana’s other customers. The LPSC staff also recommended that the LPSC deny approval of the corporate sustainability rider terms providing for the customer to supply funding toward the cost of installing carbon capture and storage infrastructure at Entergy Louisiana’s Lake Charles Power Station. The Louisiana Energy Users Group and other intervenors recommended that the LPSC require various changes to the terms of the electric service agreement with the customer that would shift additional risk and cost to the customer rather than Entergy Louisiana’s broader customer base. Certain intervenors also challenged approval on the basis that Entergy Louisiana did not conduct a request for proposals to procure the proposed generation resources to serve the customer’s project; these intervenors also advocated that Entergy Louisiana be required to procure more renewable generation and evaluate transmission alternatives rather than proceeding with development of all of the proposed new generation resources. In May 2025, Entergy Louisiana filed its rebuttal testimony responding to the direct and cross-answering testimony of the LPSC staff and intervenors. The rebuttal testimony expressed support for or no opposition to the LPSC’s adoption of certain of the proposed recommendations and identified why other proposed recommendations should not be adopted. In addition, the rebuttal testimony stated that the negotiations related to the increase in the load amount for the customer’s project had concluded and that a rider to the electric service agreement reflecting this increase had been executed. In advance of the July 2025 hearing, Entergy Louisiana reached a settlement agreement with the LPSC staff and three separate intervenors. In August 2025 the LPSC issued an order accepting the settlement agreement. Franklin Farms Power Station Units 1 and 2 are expected to be in service in 2028, and Waterford 5 Power Station is expected to be in service in 2029. In January 2026, several months after the LPSC order became final, certain intervenors filed a motion asking the LPSC to investigate the financing arrangements that the customer implemented for its data center project and to initiate a prudence review. The motion questions whether the credit protections for the customer’s obligations under the electric service agreement are adversely affected by the change in the customer’s financial structure and asks the LPSC to initiate a review of whether Entergy Louisiana withheld relevant information from the LPSC at the time of the LPSC’s order. Entergy Louisiana filed its opposition to the motion in February 2026.

Amite South Transmission Projects

In March 2024, Entergy Louisiana filed an application seeking an exemption determination, or alternatively, a certificate of public convenience and necessity, for a transmission project that includes a new 500 kV/230 kV Commodore substation and an approximately 60-mile 230 kV line connecting the new Commodore substation to the Waterford substation. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, also includes certain common elements with, and right-of-way acquisition for, a future transmission project in the same area consisting of 500 kV elements. The estimated cost of the project is $498.8 million. In February 2025, Entergy Louisiana and the LPSC staff jointly filed, for consideration by the LPSC, an uncontested stipulated

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

settlement agreement resolving all issues in the proceeding. In the motion requesting approval of the uncontested stipulated settlement agreement, the parties requested a settlement hearing in March 2025. The LPSC approved the uncontested stipulated settlement agreement in March 2025 and thereby granted certification of the project.

In December 2024, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 84-mile Commodore to Churchill 500 kV transmission line, the expansion of the Waterford 500 kV substation, the construction of a new Churchill 500 kV substation and improvements to the Churchill 230 kV substation, and the conversion of the existing 230 kV Waterford to Churchill transmission line to 500 kV, forming a 500 kV loop into the Downstream of Gypsy load pocket. The project, which was approved by MISO in the 2023 MISO Transmission Expansion Plan, shares common elements with a future transmission project in the same area consisting of 230 kV elements. The estimated cost of the project is $954.7 million. In April 2025 the LPSC staff and the Louisiana Energy Users Group, an intervenor, filed direct testimony. The LPSC staff’s testimony recommends LPSC approval of the project. The Louisiana Energy Users Group’s testimony opines that Entergy Louisiana has shown that there is a need for additional transmission investment in the West Bank area of Amite South but recommends that the LPSC withhold approval pending further analysis, including analysis of potential lower cost alternatives to the proposed project, and also pending Entergy Louisiana demonstrating that it has contributions in aid of construction from the customers whose block load additions would be enabled by the proposed transmission project in amounts sufficient to substantially, if not fully, cover the revenue requirement of the proposed project. In June 2025, Entergy Louisiana filed rebuttal testimony. A hearing was held in August 2025. In November 2025 the presiding ALJ issued a proposed recommendation granting the application and the requested certification. The Louisiana Energy Users Group filed exceptions to the proposed recommendation, and the LPSC staff and Entergy Louisiana filed responses in opposition to those exceptions. In December 2025 the ALJ issued a final recommendation granting the application and the requested certification. In December 2025 the LPSC issued an order adopting the final recommendation granting the application and the requested certification.

Cottonwood Power Station

In December 2025, Entergy Louisiana filed an application seeking LPSC approval and a certificate of convenience and necessity to acquire the Cottonwood combined cycle combustion turbine facility, a 1,263 MW combined cycle facility in Deweyville, Texas that was originally placed in commercial service in 2003. The filing seeks findings from the LPSC that the costs of the acquisition, including the approximately $1.5 billion purchase price and $309.3 million in capital upgrades and maintenance items needed to bring Cottonwood into alignment with Entergy Louisiana’s fleet standards with respect to operations and safety, are eligible for recovery in customer rates. The application requests an LPSC decision by October 2026. A procedural schedule has been set with a hearing scheduled for September 2026. The acquisition is currently targeted to occur in January 2027.

Babel - Webre 500 kV Transmission Project

In December 2025, Entergy Louisiana filed an application with the LPSC seeking a certificate of public convenience and necessity for a 500 kV transmission project that includes the construction of a new 147-mile Babel to Webre 500 kV transmission line, the reconstruction of the Webre 500 kV switching station in Louisiana, and coordination with Entergy Texas of the construction of an approximately 4-mile 500 kV transmission line in Texas. The project was approved by MISO in the 2025 MISO Transmission Expansion Plan and has an estimated cost of $1,238 million and an estimated in-service date of August 2029. The application requests an LPSC decision by June 2026.

Waterford 6 Power Station and Westlake Power Station

In February 2026, Entergy Louisiana filed an application seeking LPSC approval and certification to construct two 754 MW combined cycle combustion turbine generators, the Waterford 6 Power Station and the Westlake Power Station, to be located at Entergy Louisiana’s existing Waterford site near Killona, Louisiana and

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

existing Roy S. Nelson site in Westlake, Louisiana, respectively. In its application, Entergy Louisiana noted the estimated costs are approximately $2,027 million for the Waterford 6 Power Station and $2,091 million for the Westlake Power Station. Entergy Louisiana asked that the LPSC consider the requests in the application at or before its December 2026 meeting. The estimated in-service dates for the Waterford 6 Power Station and Westlake Power Station are July 2030 and October 2030, respectively.

Resilience and Grid 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 program’s costs. Phase I in the December 2022 application reflected the first five years of a ten-year resilience plan and included investment of approximately $5 billion, including hardening investment, transmission dead-end structures, enhanced vegetation management, and telecommunications improvement. In April 2024 the LPSC approved a framework which includes an initial five-year resilience plan providing for an investment of approximately $1.9 billion with cost recovery via a forward-looking rider with semi-annual true-ups. The plan is subject to specified reporting requirements and includes a performance review of the hardened assets. The LPSC order approving the framework does not include any restrictions on Entergy Louisiana’s ability to file applications for approval of additional investments in resilience.

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. These rulemakings were formally closed in August 2025 without the adoption of any rules or obligations being promulgated by the LPSC.

Sources of Capital

Entergy Louisiana’s sources to meet its capital requirements include:

internally generated funds;
cash on hand;
the Entergy system money pool;
storm reserve escrow accounts;
debt or preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
capital contributions; and
bank financing under new or existing facilities.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

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 requirements set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Louisiana’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.


2025	2024	2023	2022
(In Thousands)
$63,435	$32,668	($156,166)	($226,114)

See Note 4 to the financial statements for a description of the money pool.

Entergy Louisiana has a credit facility in the amount of $400 million scheduled to expire in June 2030. 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, 2025, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Louisiana is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO. As of December 31, 2025, $164.1 million in letters of credit were outstanding under Entergy Louisiana’s uncommitted letter of credit facilities. 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 2027. As of December 31, 2025, $50.3 million in loans were outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity and $43.7 million in loans were outstanding under the Entergy Louisiana Waterford nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facilities.

Entergy Louisiana obtained authorizations from the FERC through January 2027 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.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

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

Filings with the LPSC

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 were only 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 were 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 was 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, was $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. In September 2024 the LPSC issued an order approving a settlement that resolved, with prejudice, all other issues identified by the staff in the matter and closed the docket. See “2023 Entergy Louisiana Rate Case and Formula Rate Plan Extension Request” below for further discussion.

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 contained 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 was Entergy Louisiana’s recommended path; or (2) implementation of rates resulting from a cost-of-service study (the Rate Case path). The application complied 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. Entergy Louisiana’s filing supported the need to extend Entergy Louisiana’s formula rate plan with credit supportive mechanisms needed to facilitate investment in the distribution, transmission, and generation functions.

In July 2024, Entergy Louisiana reached an agreement in principle with the LPSC staff and the intervenors in the proceeding and filed with the LPSC a joint motion to suspend the procedural schedule to allow for all parties to finalize a stipulated settlement agreement.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

In August 2024, Entergy Louisiana and the LPSC staff jointly filed a global stipulated settlement agreement for consideration by the LPSC with key terms as follows:

continuation of the formula rate plan for 2024-2026 (test years 2023-2025);
a base formula rate plan revenue increase of $120 million for test year 2023, effective for rates beginning September 2024;
a $140 million cumulative cap on base formula rate plan revenue increases, if needed, for test years 2024 and 2025, excluding outside the bandwidth items;
$184 million of customer rate credits to be given over two years, including increasing customer sharing of income tax benefits resulting from the 2016-2018 IRS audit, to resolve any remaining disputed issues stemming from formula rate plan test years prior to test year 2023, including but not limited to the investigation into Entergy Services costs billed to Entergy Louisiana. As discussed in Note 3 to the financial statements, a $38 million regulatory liability was recorded in 2023 in connection with the 2016-2018 IRS audit;
$75.5 million of customer rate credits, as provided for in the System Energy global settlement, to be credited over three years subject to and conditioned upon FERC approval of the System Energy global settlement, which was approved in November 2024. See “Complaints Against System Energy – System Energy Settlement with the LPSC” in Note 2 to the financial statements for further details of the System Energy global settlement;
$5.8 million of customer rate credits provided for in the Entergy Louisiana formula rate plan global settlement agreement approved by the LPSC in November 2023 credited over one year. See “Formula Rate Plan Global Settlement” below for further discussion of the settlement;
an increase in the allowed midpoint return on common equity from 9.5% to 9.7%, with a bandwidth of 40 basis points above and below the midpoint, for the extended term of the formula rate plan, except that for test year 2023 in which the authorized return on common equity shall have no bearing on the change in base formula rate plan revenue described above and, for test year 2024, any earnings above the authorized return on common equity shall be returned to customers through a credit;
an increase in nuclear depreciation rates by $15 million in each of the 2023, 2024, and 2025 test years outside of the formula rate plan bandwidth calculation; and
for the transmission recovery mechanism and the distribution recovery mechanism, no change to the existing floors, but the caps for both would be $350 million for test year 2023, $375 million for test year 2024, and $400 million for test year 2025. Transmission projects filed with the LPSC will be exempt from the transmission recovery mechanism cap.

The global stipulated settlement agreement was unanimously approved by the LPSC in August 2024 and an order was issued by the LPSC in September 2024 reflecting the approval of the settlement.

Based on the July 2024 agreement in principle, in second quarter 2024 Entergy Louisiana recorded expenses of $151 million ($112 million net-of-tax) primarily consisting of regulatory charges to reflect the effects of the agreement in principle.

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, primarily associated with the Hurricane Isaac securitization, initially recognized in 2017 as a result of the Tax Cuts and Jobs Act.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

2023 Formula Rate Plan Filing

In August 2024, pursuant to the global stipulated settlement agreement approved by the LPSC also in August 2024, Entergy Louisiana filed its formula rate plan evaluation report for its 2023 calendar year operations. Consistent with the global stipulated settlement agreement, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the 2023 test year, however, the bandwidth provisions of the formula rate plan were temporarily suspended and, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana implemented the September 2024 formula rate plan rate adjustments effective with the first billing cycle of September 2024. Those adjustments included a $120 million increase in base rider formula rate plan revenue and a $101.8 million one-time incremental net decrease consistent with the terms of the global stipulated settlement. The formula rate plan rate adjustments reflected in the evaluation report also include a redetermination of the transmission recovery mechanism, the distribution recovery mechanism, the additional capacity mechanism, the tax adjustment mechanism, the MISO cost recovery mechanism, and other one-time adjustments. In January 2025, Entergy Louisiana and the LPSC filed a joint report indicating that no disputed issues remained in the proceeding and requesting that the LPSC issue an order accepting Entergy Louisiana’s evaluation report and, ultimately, resolving this matter. In March 2025 the LPSC issued an order accepting the evaluation report.

In December 2024, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana filed an interim rate adjustment for the 2023 test year reflecting the return of $25.1 million of refunds from the System Energy settlement with the LPSC to customers from January through August 2025. In February 2025, pursuant to the terms of the global stipulated settlement agreement, Entergy Louisiana filed a second interim rate adjustment for the 2023 test year reflecting the divestiture of Entergy Louisiana’s share of Grand Gulf capacity and energy, which was effective as of January 1, 2025. The second interim rate adjustment also reflected a revenue increase of $17.8 million for the recovery of Hurricane Francine costs as approved by the LPSC (on an interim basis). The second interim rate adjustment was implemented with the first billing cycle of March 2025. See further discussion of the Hurricane Francine proceeding in “Storm Cost Recovery Filings with Retail Regulators – Entergy Louisiana – Hurricane Francine” in Note 2 to the financial statements. See Note 8 to the financial statements for discussion of Entergy Louisiana’s divestiture from the Unit Power Sales Agreement.

2024 Formula Rate Plan Filing

In May 2025, Entergy Louisiana filed its formula rate plan evaluation report for its 2024 calendar year operations. Consistent with the global stipulated settlement agreement approved by the LPSC in August 2024, the filing reflected a 9.7% allowed return on common equity with a bandwidth of 40 basis points above and below the midpoint. For the test year 2024, however, any earnings above the allowed return on common equity were to be returned to customers through a credit, pursuant to the terms of the global stipulated settlement agreement. The 2024 test year evaluation produced an earned return on common equity of 9.98%, which was within the approved formula rate plan bandwidth, but above the allowed return on common equity, resulting in customer credits of $31.9 million which were returned to customers during September and October 2025.

Other changes in formula rate plan revenue were driven by higher nuclear depreciation rates, additions to transmission and distribution plant in service reflected through the transmission recovery mechanism and distribution recovery mechanism, and the expiration of customer credits related to the LPSC’s order, offset by increased customer credits resulting from an increase in net MISO revenues reflected through the MISO cost recovery mechanism and the reduction in the Louisiana corporate income tax rate effective January 1, 2025, reflected through the tax adjustment mechanism, as discussed below. Excluding the customer credit for earnings above the authorized return on common equity discussed above, the net result of these changes on an annualized basis was a $2 million increase in formula rate plan revenue.

As noted above, the 2024 evaluation report included the effects of the change in Louisiana state tax law that reduced the corporate income tax rate to a flat 5.5% (from the then-current highest marginal rate of 7.5%) effective

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

January 1, 2025. As such, the 2024 evaluation report reflected the calculation of current and deferred income tax expenses as well as the revaluation of accumulated deferred income taxes based on the income tax laws currently in effect. The 2024 evaluation report proposed that the rate effects associated with the revaluation of accumulated deferred income taxes, including the collection of any net accumulated deferred income tax deficiency and any related effects on rate base, should be reflected in the tax adjustment mechanism consistent with the treatment of similar Tax Cuts and Jobs Act and prior state tax change-related impacts. The effects of the change in tax law on Entergy Louisiana’s authorized return on rate base were also reflected in the 2024 evaluation report consistent with the treatment cited above, including a credit in the extraordinary cost change mechanism for the prospective change in Entergy Louisiana’s authorized return and a credit within the tax adjustment mechanism for over-collection of income tax expense through August 2025. Subject to LPSC review, the resulting changes from the 2024 formula rate plan evaluation report became effective for bills rendered during the first billing cycle of September 2025, subject to refund. In August 2025 the LPSC staff filed its errors and objections report, as required by the formula rate plan’s process, and found that Entergy Louisiana’s formula rate plan is in compliance with the LPSC’s requirements and the global stipulated settlement agreement. The LPSC staff reserved the right to determine whether Entergy Louisiana appropriately credited certain revenues to customers during the September and October 2025 billing cycles. In December 2025 the LPSC staff and Entergy Louisiana filed a joint report indicating that no unresolved, disputed issues existed and recommending that the LPSC accept the joint report, confirm that no outstanding issues existed, and close the docket. In January 2026 the LPSC issued an order accepting the joint report.

Fuel and purchased power cost recovery

Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments, which ceased following the sale of its natural gas distribution business on July 1, 2025, included estimates for the billing month adjusted by a surcharge or credit that arose from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 14 to the financial statements for discussion of the sale of Entergy Louisiana’s natural gas distribution business on July 1, 2025.

In March 2020 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2016 through 2019. The LPSC staff issued its audit report in September 2021, and although certain internal record keeping recommendations were made, the LPSC staff did not recommend any disallowances. The next step is for the LPSC to issue its final report, but there is not a deadline or timing requirement associated with the issuance of the final report.

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 over/under calculation of the fuel adjustment clause, which was intended to recover the full amount of the costs included on a rolling twelve-month basis.

In January 2023 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2020 through 2022. Discovery is ongoing, and no audit report has been filed.

In June 2025 the LPSC staff provided notice of an audit of Entergy Louisiana’s purchased gas adjustment clause filings (for Entergy Louisiana’s gas operations). The audit includes a review of the reasonableness of charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from January 2023 through June 2025. Discovery is ongoing, and no audit report has been filed.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Industrial and Commercial Customers

Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Louisiana responds by working with industrial and commercial customers to negotiate electric service contracts with competitive rates that match specific customer needs and load profiles. Additionally, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

Federal Regulation

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 acquisition, 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.

Environmental Risks

Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Louisiana’s financial statements in conformity with 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 Louisiana’s financial position, results of operations, or cash flows.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Nuclear Decommissioning Costs

Utility Regulatory Accounting

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are 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 2026 Qualified Pension Cost	Impact on 2025 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$887	$24,201
Rate of return on plan assets	(0.25%)	$2,825	$—
Rate of increase in compensation	0.25%	$1,106	$5,453

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 2026 Postretirement Benefits Cost	Impact on 2025 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$405	$4,434
Health care cost trend	0.25%	$486	$2,504

Each fluctuation above assumes that the other components of the calculation are held constant.

Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Costs and Employer Contributions

Total qualified pension cost for Entergy Louisiana in 2025 was $16.9 million, including $6 million in settlement costs. Entergy Louisiana anticipates 2026 qualified pension cost to be $7.9 million. Entergy Louisiana contributed $41.3 million to its qualified pension plans in 2025 and estimates pension contributions will be approximately $41.6 million in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026.

Total postretirement health care and life insurance benefit income for Entergy Louisiana in 2025 was $5.6 million, including $2.1 million in settlement and curtailment credits. Entergy Louisiana expects 2026 postretirement health care and life insurance benefit costs of approximately $5.3 million. Entergy Louisiana contributed $15.8 million to its other postretirement plans in 2025 and estimates that 2026 contributions will be approximately $14.1 million.

Other Contingencies

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 Louisiana, LLC and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, cash flows, and changes in equity (pages 377 through 382 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for 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 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 the likelihood of 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 refund 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 19, 2026

We have served as the Company’s auditor since 2001.


ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING REVENUES
Electric	$5,687,813	$5,068,158	$5,073,239
Natural gas	44,286	75,860	74,531
TOTAL	5,732,099	5,144,018	5,147,770

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	1,311,773	1,026,343	1,080,485
Purchased power	895,174	670,874	654,721
Nuclear refueling outage expenses	53,638	76,020	63,429
Other operation and maintenance	1,136,573	1,097,283	1,097,233
Decommissioning	78,992	80,663	75,962
Taxes other than income taxes	261,530	248,472	245,191
Depreciation and amortization	806,376	770,904	726,389
Other regulatory charges (credits) - net	(176,001)	41,525	41,209
TOTAL	4,368,055	4,012,084	3,984,619

OPERATING INCOME	1,364,044	1,131,934	1,163,151

OTHER INCOME
Allowance for equity funds used during construction	54,958	36,782	32,160
Interest and investment income	166,792	146,494	90,316
Interest and investment income - affiliated	299,135	315,433	303,233
Miscellaneous - net	(66,313)	(123,280)	(160,972)
TOTAL	454,572	375,429	264,737

INTEREST EXPENSE
Interest expense	488,974	403,473	375,295
Allowance for borrowed funds used during construction	(21,071)	(12,290)	(14,996)
TOTAL	467,903	391,183	360,299

INCOME BEFORE INCOME TAXES	1,350,713	1,116,180	1,067,589

Income taxes	237,813	225,409	(205,781)

NET INCOME	1,112,900	890,771	1,273,370

Net income attributable to noncontrolling interests	2,952	3,126	2,988

EARNINGS APPLICABLE TO MEMBER'S EQUITY	$1,109,948	$887,645	$1,270,382

See Notes to Financial Statements.


ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

Net Income	$1,112,900	$890,771	$1,273,370

Other comprehensive loss
Pension and other postretirement plan changes
(net of tax benefit of $8,256, $421, and $211)	(19,742)	(1,140)	(572)
Other comprehensive loss	(19,742)	(1,140)	(572)

Comprehensive Income	1,093,158	889,631	1,272,798
Net income attributable to noncontrolling interests	2,952	3,126	2,988
Comprehensive Income Applicable to Member's Equity	$1,090,206	$886,505	$1,269,810

See Notes to Financial Statements.


ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)
OPERATING ACTIVITIES
Net income	$1,112,900	$890,771	$1,273,370
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	973,816	937,246	864,225
Deferred income taxes, tax credits, and non-current taxes accrued	551,267	259,474	(99,812)
Changes in working capital:
Receivables	(16,151)	4,248	55,140
Fuel inventory	14,249	7,601	(15,959)
Accounts payable	48,350	(6,123)	(100,321)
Taxes accrued	35,778	(37,448)	30,459
Interest accrued	6,163	28,530	(9,680)
Deferred fuel costs	(20,366)	29,494	134,383
Other working capital accounts	335,100	84,692	(129,173)
Changes in provisions for estimated losses	(18,963)	15,754	(52,445)
Changes in other regulatory assets	106,205	1,937	407,327
Changes in other regulatory liabilities	(110,727)	452,731	225,645
Effect of securitization on regulatory asset	—	—	(491,150)
Changes in pension and other postretirement funded status	(72,455)	(117,627)	(117,886)
Other	(203,445)	(303,717)	57,997
Net cash flow provided by operating activities	2,741,721	2,247,563	2,032,120
INVESTING ACTIVITIES
Construction expenditures	(3,065,462)	(1,633,669)	(1,624,181)
Allowance for equity funds used during construction	54,958	36,782	32,160
Nuclear fuel purchases	(160,003)	(125,315)	(162,079)
Proceeds from sale of nuclear fuel	17,230	63,297	30,214
Payments to storm reserve escrow account	(11,700)	(12,899)	(14,449)
Receipts from storm reserve escrow account	33,456	—	64,036
Purchase of preferred membership interests of affiliate	—	—	(1,457,676)
Redemption of preferred membership interests of affiliate	249,078	239,249	125,002
Proceeds from nuclear decommissioning trust fund sales	727,260	1,185,491	575,596
Investment in nuclear decommissioning trust funds	(792,413)	(1,242,466)	(633,029)
Changes in money pool receivable - net	(30,767)	(32,668)	—
Payment for purchase of assets	(41,435)	—	—
Proceeds from sale of business and assets	200,673	2,109	—
Insurance proceeds received for property damages	—	7,907	19,493
Decrease (increase) in other investments	(58,424)	35	5,457
Net cash flow used in investing activities	(2,877,549)	(1,512,147)	(3,039,456)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	2,098,625	2,743,965	1,410,893
Retirement of long-term debt	(1,605,837)	(2,305,336)	(2,699,235)
Proceeds received by storm trusts related to securitization	—	—	1,457,676
Capital contribution from parent	—	—	1,457,676
Changes in money pool payable - net	—	(156,166)	(69,948)
Customer advances received for construction	1,265,745	285,798	105,622
Customer advances used for construction	(405,057)	(109,058)	(39,714)
Common equity distributions paid	(756,250)	(859,100)	(660,750)
Other	(11,539)	(11,189)	(8,725)
Net cash flow provided by (used in) financing activities	585,687	(411,086)	953,495
Net increase (decrease) in cash and cash equivalents	449,859	324,330	(53,841)
Cash and cash equivalents at beginning of period	327,102	2,772	56,613
Cash and cash equivalents at end of period	$776,961	$327,102	$2,772
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$413,547	$366,384	$376,353
Income taxes - net (includes production tax credit sale proceeds of $198,285 in 2025, $— in 2024, and $— in 2023)	($344,295)	$16,882	($141,143)
Non-cash investing activities:
Accrued construction expenditures	$267,887	$124,077	$105,859

See Notes to Financial Statements.


ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2025	2024
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$237	$327
Temporary cash investments	776,724	326,775
Total cash and cash equivalents	776,961	327,102
Accounts receivable:
Customer	292,366	294,089
Allowance for doubtful accounts	(9,069)	(3,036)
Associated companies	164,911	103,055
Other	50,471	39,056
Accrued unbilled revenues	194,429	213,026
Total accounts receivable	693,108	646,190
Deferred fuel costs	15,672	—
Fuel inventory - at average cost	35,968	49,515
Materials and supplies	792,217	782,459
Deferred nuclear refueling outage costs	40,683	31,121

Current assets held for sale	—	2,474
Prepayments and other	187,832	84,236
TOTAL	2,542,441	1,923,097

OTHER PROPERTY AND INVESTMENTS
Investment in affiliate preferred membership interests	4,007,919	4,256,997
Decommissioning trust funds	2,753,828	2,429,088
Non-utility property - at cost (less accumulated depreciation)	459,706	410,611
Storm reserve escrow account	234,961	256,718
Other	10,132	9,749
TOTAL	7,466,546	7,363,163

UTILITY PLANT
Electric	30,408,352	28,736,547
Natural gas	—	33,775
Construction work in progress	2,031,650	761,090
Nuclear fuel	323,052	288,084
TOTAL UTILITY PLANT	32,763,054	29,819,496
Less - accumulated depreciation and amortization	11,275,981	10,794,817
UTILITY PLANT - NET	21,487,073	19,024,679

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets	1,540,709	1,637,967
Deferred fuel costs	168,122	168,122
Non-current assets held for sale	—	173,669
Other	132,679	57,853
TOTAL	1,841,510	2,037,611

TOTAL ASSETS	$33,337,570	$30,348,550

See Notes to Financial Statements.


ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2025	2024
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$720,000	$300,000
Accounts payable:
Associated companies	92,126	108,688
Other	761,359	533,087
Customer deposits	172,594	169,544
Taxes accrued	64,793	29,002
Interest accrued	126,349	120,186
Deferred fuel costs	—	5,421
Customer advances	543,312	151,662
Other	94,876	96,426
TOTAL	2,575,409	1,514,016

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	3,093,218	2,477,954
Accumulated deferred investment tax credits	84,177	88,679
Regulatory liability for income taxes - net	312,684	355,432
Other regulatory liabilities	1,630,763	1,692,547
Decommissioning	1,932,412	1,842,855
Accumulated provisions	260,660	279,623
Pension and other postretirement liabilities	159,075	160,577
Long-term debt	9,646,835	9,566,453
Customer advances for construction	1,152,530	291,842
Other	558,621	479,178
TOTAL	18,830,975	17,235,140

Commitments and Contingencies

EQUITY
Member’s equity	11,857,063	11,503,030
Accumulated other comprehensive income	33,916	53,658
Noncontrolling interests	40,207	42,706
TOTAL	11,931,186	11,599,394

TOTAL LIABILITIES AND EQUITY	$33,337,570	$30,348,550

See Notes to Financial Statements.


ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2025, 2024, and 2023

	Noncontrolling Interests	Member’s Equity	Accumulated Other Comprehensive Income	Total
	(In Thousands)

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)
Distribution to LURC	(4,193)	—	—	(4,193)
Other	—	(37)	—	(37)
Balance at December 31, 2023	$45,107	$11,473,614	$54,798	$11,573,519
Net income	3,126	887,645	—	890,771
Other comprehensive loss	—	—	(1,140)	(1,140)
Non-cash contribution from parent	—	976	—	976
Common equity distributions	—	(859,100)	—	(859,100)
Distributions to LURC	(5,527)	—	—	(5,527)
Other	—	(105)	—	(105)
Balance at December 31, 2024	$42,706	$11,503,030	$53,658	$11,599,394
Net income	2,952	1,109,948	—	1,112,900
Other comprehensive loss	—	—	(19,742)	(19,742)
Non-cash contribution from parent	—	386	—	386
Common equity distributions	—	(756,250)	—	(756,250)
Distributions to LURC	(5,451)	—	—	(5,451)
Other	—	(51)	—	(51)
Balance at December 31, 2025	$40,207	$11,857,063	$33,916	$11,931,186

See Notes to Financial Statements.

ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Winter Storm Fern

See the “Winter Storm Fern” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Winter Storm Fern. Entergy Mississippi’s preliminary estimate for the cost of mobilizing crews and restoring power is approximately $170 million to $200 million, with the majority of the costs being capital. Natural gas purchases for Entergy Mississippi for January 2026 are $85 million compared to natural gas purchases for January 2025 of $28 million.

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $63.3 million primarily due to higher retail electric price, higher volume/weather, higher other income, a return on construction work in progress for certain utility plant investments in 2025, and $10.2 million of liquidated damages, net of customer sharing, recognized in 2025 resulting from a counterparty’s termination of a purchased power agreement. The increase was partially offset by higher other operation and maintenance expenses, higher interest expense, and a regulatory charge, recorded in the first quarter 2025, to reflect an adjustment to the grid modernization over/under recovery deferral balance.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:


			Amount
			(In Millions)
2024 operating revenues			$1,764.6
Fuel, rider, and other revenues that do not significantly affect net income			57.4
Retail electric price			53.2
Volume/weather			50.2
Return on construction work in progress for certain utility plant investments			20.1
Purchased power agreement termination proceeds			10.2
2025 operating revenues			$1,955.7

Entergy Mississippi’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The retail electric price variance is primarily due to increases in formula rate plan rates effective April 2024 and July 2024 and an increase in formula rate plan rates resulting from an increase in interim facilities rate adjustment revenues effective January 2025. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing and the interim facilities rate adjustment.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The volume/weather variance is primarily due to an increase in industrial usage and the effect of more favorable weather on residential sales. The increase in industrial usage is primarily due to an increase in demand from large industrial customers, primarily in the data centers and technology industries, partially offset by a decrease in demand from small industrial customers.

The purchased power agreement termination proceeds variance represents $10.2 million of liquidated damages, net of customer sharing, recognized in 2025 resulting from a counterparty’s termination of a purchased power agreement. See Note 2 to the financial statements for discussion of the customer sharing included in the power management cost factor effective for February 2026 bills.

Total electric energy sales for Entergy Mississippi for the years ended December 31, 2025 and 2024 are as follows:


	2025	2024	% Change
	(GWh)
Residential	5,586	5,443	3
Commercial	4,609	4,587	—
Industrial	2,761	2,317	19
Governmental	398	397	—
Total retail	13,354	12,744	5
Sales for resale:
Non-associated companies	4,966	5,568	(11)
Total	18,320	18,312	—

See Note 19 to the financial statements for additional discussion of Entergy Mississippi’s operating revenues.

Other Income Statement Variances

Other operation and maintenance expenses increased primarily due to:

an increase of $32.1 million in power delivery expenses primarily due to higher vegetation maintenance expenses;
an increase of $13.8 million in non-nuclear generation expenses primarily due to a higher scope of work performed in 2025 as compared to 2024; and
an increase of $5.8 million in bad debt expense.

The increase was partially offset by contract costs of $7.2 million in 2024 related to operational performance, customer service, and organizational health initiatives.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments and millage rate increases.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Other regulatory charges (credits) – net includes:

a regulatory charge of $21 million, recorded in first quarter 2025, to reflect an adjustment to the grid modernization over/under recovery deferral balance; and
regulatory credits of $7.3 million, recorded in second quarter 2024, to reflect the effects of the joint stipulation reached in the 2024 formula rate plan filing proceeding. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing.

Other income increased primarily due to an increase of $14.6 million in interest earned on money pool investments and an increase of $12.1 million in the amortization of tax gross ups on customer advances, including customer advances for construction.

Interest expense increased primarily due to the issuance of $600 million of 5.80% Series mortgage bonds in March 2025, the issuance of $300 million of 5.85% Series mortgage bonds in May 2024, and carrying costs of $12.4 million in 2025 on customer advances, including customer advances for construction. The increase was partially offset by a decrease of $3.8 million in carrying costs related to the deferred fuel balance.

The effective income tax rates were 23.5% for 2025 and 24.7% for 2024. 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.

2024 Compared to 2023

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, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.

Income Tax Legislation and Regulation

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:


	2025	2024	2023
	(In Thousands)
Cash and cash equivalents at beginning of period	$155,693	$6,630	$16,979

Net cash provided by (used in):
Operating activities	704,694	699,455	559,391
Investing activities	(1,446,073)	(705,219)	(527,978)
Financing activities	927,170	154,827	(41,762)
Net increase (decrease) in cash and cash equivalents	185,791	149,063	(10,349)

Cash and cash equivalents at end of period	$341,484	$155,693	$6,630

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $5.2 million in 2025 primarily due to:

the receipt of $133.4 million in advance payments related to customer agreements in 2025, of which $108.4 million is recorded as current liabilities and included within changes in other working capital accounts;
the receipt of $69.7 million in payments from System Energy in 2025 in accordance with the Unit Power Sales Agreement related to the transfer of 2024 nuclear production tax credits by System Energy to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits;
higher collections from customers; and
the receipt of a $15.0 million liquidated damages payment in third quarter 2025 resulting from a counterparty’s termination of a purchased power agreement.

The increase was substantially offset by:

the timing of payments to vendors;
income tax payments of $82.5 million in 2025 as compared to income tax refunds of $14.2 million in 2024. Entergy Mississippi made income tax payments in 2025 and received income tax refunds in 2024, each in accordance with Entergy’s tax allocation agreement; and
higher fuel and purchased power payments. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery.

Investing Activities

Net cash flow used in investing activities increased $740.9 million in 2025 primarily due to an increase of $757.6 million in non-nuclear generation construction expenditures primarily due to higher spending on the Delta Blues Advanced Power Station project, the Vicksburg Advanced Power Station project, the Traceview Advanced Power Station project, the Penton Solar project, and the Delta Solar project and an increase of $42.4 million in distribution construction expenditures primarily due to higher capital expenditures for storm restoration in 2025. The increase was partially offset by:

a decrease of $23.1 million in transmission construction expenditures primarily due to decreased spending on various transmission projects in 2025;
the receipt of a $14.5 million initial payment for the sale of transmission rights and excess land related to Entergy Mississippi’s interest in the Independence power plant in third quarter 2025; and
a decrease of $8.9 million in information technology capital expenditures primarily due to decreased spending on various technology projects in 2025.

Financing Activities

Net cash flow provided by financing activities increased $772.3 million in 2025 primarily due to:

the issuance of $600 million of 5.80% Series mortgage bonds in March 2025;
capital contributions of $265.5 million received from Entergy Corporation in 2025 in order to maintain Entergy Mississippi’s capital structure;
the repayment, prior to maturity, of $100 million of 3.75% Series mortgage bonds in June 2024;
money pool activity; and
$44.6 million in common equity distributions paid in 2024 in order to maintain Entergy Mississippi’s capital structure.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The increase was partially offset by the issuance of $300 million of 5.85% Series mortgage bonds in May 2024.

Decreases in Entergy Mississippi’s payable to the money pool are a use of cash flow, and Entergy Mississippi’s payable to the money pool decreased $73.8 million in 2024. 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 additional details of long-term debt.

2024 Compared to 2023

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, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.

Capital Structure

Entergy Mississippi’s debt to capital ratio is shown in the following table.


	December 31, 2025		December 31, 2024
Debt to capital	50.5	%	50.4	%
Effect of subtracting cash	(2.9	%)	(1.6	%)
Net debt to net capital (non-GAAP)	47.6	%	48.8	%

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.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Uses of Capital

Entergy Mississippi requires capital resources for:

construction and other capital investments;
debt maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
distributions and interest payments.

Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.


	2026	2027	2028	2029
	(In Millions)
Planned construction and capital investment:
Generation	$1,460	$1,240	$415	$120
Transmission	230	160	140	110
Distribution	370	345	325	350
Utility Support	45	65	45	35
Total	$2,105	$1,810	$925	$615

In addition to routine capital spending to maintain operations, the planned capital investment estimate includes investments in generation projects to modernize, decarbonize, expand, and diversify Entergy Mississippi’s portfolio, as well as to support customer growth, including Delta Blues Advanced Power Station, Delta Solar, Penton Solar, Traceview Advanced Power Station, and Vicksburg Advanced Power Station; distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience while also supporting customer growth and 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, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Mississippi’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Mississippi’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect Entergy Mississippi’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy Mississippi’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.

Entergy Mississippi has incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on its current and planned capital projects. Entergy Mississippi is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Following are the amounts of Entergy Mississippi’s existing debt and lease obligations (includes estimated interest payments).


	2026	2027	2028	2029-2030	After 2030

Long-term debt (a)	$133	$283	$497	$235	$4,878
Operating leases (b)	$10	$9	$8	$7	$3
Finance leases (b)	$4	$4	$3	$5	$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 $4 million to its qualified pension plans and approximately $176 thousand to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026. 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.

Additional Generation and Transmission Resources

In March 2024, Entergy Mississippi executed a large customer supply and service agreement to serve two data center campuses located in Madison County, Mississippi in which Amazon Web Services is investing. In February 2025, Entergy Mississippi also executed a large customer supply and service agreement to serve a data center campus located in Warren County, Mississippi in which Amazon Web Services is investing. Entergy Mississippi will need generation and transmission resources to reliably serve all Entergy Mississippi customers, including the data centers. The large customer supply and service agreements also contain provisions which cover Entergy Mississippi’s incremental investment costs in the event of early termination. Entergy Mississippi anticipates recovering the incremental cost to serve the customer through the revenues it is collecting under the large customer supply and service agreements.

In May 2024 the MPSC approved Entergy Mississippi’s revisions to its formula rate plan to comply with state legislation passed in January 2024 allowing Entergy Mississippi to make interim rate adjustments, including the collection of a return on construction work in progress on a cash basis, to recover the non-fuel related annual ownership cost of certain facilities that directly or indirectly provide service to customers who own certain data

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

processing center projects as specified in the legislation. See further discussion of the interim facilities rate adjustments below.

Delta Blues Advanced Power Station

In September 2024, Entergy Mississippi announced plans to construct, own, and operate the Delta Blues Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in Washington County, Mississippi. The facility will primarily be powered by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Delta Blues Advanced Power Station is estimated to cost $1.2 billion. Construction of the Delta Blues Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi began recovery of certain costs of construction of the Delta Blues Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service by May 2028.

Delta Solar

In December 2024 the Bolivar County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Delta Solar facility, an 80 MW solar facility to be located in Bolivar County, Mississippi. The Delta Solar facility is estimated to cost $157.2 million, inclusive of estimated transmission interconnection costs. Construction of the Delta Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Delta Solar facility is expected to be in service by the end of 2027.

Penton Solar

In May 2025 the DeSoto County Board of Supervisors approved Entergy Mississippi’s plans to construct, own, and operate the Penton Solar facility, a 190 MW solar facility to be located in DeSoto County, Mississippi. The Penton Solar facility is estimated to cost $327.2 million, inclusive of estimated transmission interconnection and upgrade costs. Construction of the Penton Solar facility qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the Penton Solar facility is expected to be in service by early 2028.

Traceview Advanced Power Station

Entergy Mississippi is constructing a 754 MW combined cycle combustion turbine facility located in the City of Ridgeland, Madison County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The project is estimated to cost in excess of $1 billion. Construction of the Traceview Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Traceview Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. The facility is expected to be in service in 2029.

Vicksburg Advanced Power Station

In October 2025, Entergy Mississippi announced plans to construct, own, and operate the Vicksburg Advanced Power Station, a 754 MW combined cycle combustion turbine facility, to be located in the City of Vicksburg, Warren County, Mississippi. The facility will be powered primarily by natural gas, and it will also be enabled for future carbon capture and storage and for hydrogen co-firing optionality. The Vicksburg Advanced Power Station is estimated to cost $1.2 billion. Construction of the Vicksburg Advanced Power Station qualifies for pre-certification under Mississippi legislation providing for the pre-certification of construction of certain types of facilities that directly or indirectly provide electric service to customers who own certain data processing center projects as specified in the legislation. As provided for in this legislation, Entergy Mississippi will begin recovery of certain costs of construction of the Vicksburg Advanced Power Station through the interim facilities rate adjustments provision of its formula rate plan rider. Non-fuel revenue collected from the data center customer will be included in the formula rate plan to offset the facility’s revenue requirement. The project costs will be reviewed for prudence by the MPSC following the completion of construction. Construction is in progress, and the facility is expected to be in service in August 2028.

Sources of Capital

Entergy Mississippi’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 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 requirements 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 (payables to) the money pool were as follows as of December 31 for each of the following years.


2025	2024	2023	2022
(In Thousands)
$27,422	$15,218	($73,769)	$26,879

See Note 4 to the financial statements for a description of the money pool.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy Mississippi has a credit facility in the amount of $300 million scheduled to expire in June 2030. The 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, 2025, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy Mississippi is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO and for other purposes. As of December 31, 2025, $86.1 million in MISO letters of credit and $1.3 million in non-MISO letters of credit were outstanding under Entergy Mississippi’s uncommitted letter of credit facilities. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Mississippi obtained authorization from the FERC through January 2027 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

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, but resumed in July 2024. In June 2023 the MPSC approved the joint stipulation with rates effective in July 2023.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

2024 Formula Rate Plan Filing

In March 2024, Entergy Mississippi submitted its formula rate plan 2024 test year filing and 2023 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2023 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2024 calendar year to be below the formula rate plan bandwidth. The 2024 test year filing showed a $63.4 million rate increase was necessary to reset Entergy Mississippi’s earned return on rate base to the specified point of adjustment of 7.10%, within the formula rate plan bandwidth. The 2023 look-back filing compared actual 2023 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues. In accordance with the provisions of the formula rate plan, Entergy Mississippi implemented a $32.6 million interim rate increase, reflecting a cap equal to 2% of 2023 retail revenues, effective April 2024.

In December 2014 the MPSC ordered Entergy Mississippi to file an updated depreciation study at least once every four years. Pursuant to this order and Entergy Mississippi’s filing cycle, Entergy Mississippi would have filed an updated depreciation report with its formula rate plan filing in 2023. However, in July 2022 the MPSC directed Entergy Mississippi to file its next depreciation study in connection with its 2024 formula rate plan filing notwithstanding the MPSC’s prior order. Accordingly, Entergy Mississippi filed a depreciation study in February 2024. The study showed a need for an increase in annual depreciation expense of $55.2 million. The calculated increase in annual depreciation expense was excluded from Entergy Mississippi’s 2024 formula rate plan revenue increase request because the MPSC had not yet approved the proposed depreciation rates.

In June 2024, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2024 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. After performance adjustments, the formula rate plan reflected an earned return on rate base of 6.08% for calendar year 2024, which resulted in a total revenue increase of $64.6 million for 2024. The joint stipulation also recommended approval of a revised customer charge of $31.82 per month for residential customers and $53.10 per month for general service customers. Pursuant to the stipulation, Entergy Mississippi’s 2023 look-back filing reflected an earned return on rate base of 6.81%, resulting in an increase of $0.3 million in the formula rate plan revenues for 2023. Finally, the stipulation recommended approval of Entergy Mississippi’s proposed depreciation rates with those rates to be implemented upon request and approval at a later date. In June 2024 the MPSC approved the joint stipulation with rates effective in July 2024. The approval also included a reduction to the energy cost factor, resulting in a net bill decrease for a typical residential customer using 1,000 kWh per month. Also in June 2024, Entergy Mississippi recorded regulatory credits of $7.3 million to reflect the difference between interim rates placed in effect in April 2024 and the rates reflected in the joint stipulation.

2025 Formula Rate Plan Filing

In February 2025, Entergy Mississippi submitted its formula rate plan 2025 test year filing and 2024 look-back filing showing Entergy Mississippi’s earned return on rate base for the historical 2024 calendar year to be within the formula rate plan bandwidth and projected earned return for the 2025 calendar year to also be within the formula rate plan bandwidth. The 2025 test year filing resulted in an earned return on rate base of 7.64% and reflected no change in formula rate plan revenues. The 2024 look-back filing compared actual 2024 results to the approved benchmark return on rate base and reflected no change in formula rate plan revenues, although Entergy Mississippi proposed to adjust interim rates by $135 thousand to reflect two outside-the-bandwidth changes: (1) the completion of Entergy Mississippi’s return to customers of credits under its restructuring credit rider; and (2) a true-up of demand side management costs.

In June 2025, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation that confirmed the 2025 test year filing, with the exception of immaterial adjustments to certain operation and maintenance expenses. The formula rate plan reflected an earned return on rate base of 7.68% for calendar year 2025, resulting in no change in formula rate plan revenues for 2025. Pursuant to the stipulation, Entergy Mississippi’s 2024 look-back filing reflected an earned return on rate base of 7.55%, which also resulted in no

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

change in formula rate plan revenues for 2024. In addition, the stipulation included the recovery of the two outside-the-bandwidth changes discussed above as well as the ratemaking treatment of customer contributions, deferred revenue and prepaid contributions in aid of construction. In June 2025 the MPSC approved the joint stipulation with rates effective in July 2025.

Interim Facilities Rate Adjustments to the Formula Rate Plan

In May 2024, Entergy Mississippi received approval from the MPSC for formula rate plan revisions that were necessary for Entergy Mississippi to comply with state legislation passed in January 2024. The legislation allows Entergy Mississippi to make interim rate adjustments to recover the non-fuel related annual ownership cost of certain facilities that directly or indirectly provide service to customers who own certain data processing center projects as specified in the legislation. Entergy Mississippi filed the first of its annual interim facilities rate adjustment reports in May 2024 to recover approximately $8.7 million of these costs over a six-month period with rates effective the first billing cycle of July 2024. Entergy Mississippi filed its second annual interim facilities rate adjustment report in November 2024 to recover approximately $46.7 million of these costs over a 12-month period with rates effective the first billing cycle of January 2025. In February 2025, Entergy Mississippi filed a true-up interim facilities rate adjustment report to the initial annual interim facilities rate adjustment report filed in May 2024, reflecting the recovery of an additional approximately $1.0 million of costs over a 12-month period with rates effective with the first billing cycle of April 2025. Entergy Mississippi filed its third annual interim facilities rate adjustment report in November 2025 to recover approximately $111.3 million of these costs over a 12-month period, or approximately $64.7 million incremental to the second annual interim facilities rate adjustment report filed in November 2024, with rates effective the first billing cycle of January 2026.

Grand Gulf Capacity Filing

In September 2024, Entergy Mississippi filed a notice of intent with the MPSC to implement revisions to its unit power cost recovery rider that would allow Entergy Mississippi to recover the first year of costs associated with the transfer of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which consists of Entergy Louisiana’s interest in and purchases of Grand Gulf capacity and energy under the revised rider schedule, effective by January 1, 2025. This notice filing related to the divestiture of Entergy Louisiana’s 14% share of Grand Gulf capacity and energy under the Unit Power Sales Agreement and 2.43% share of capacity and energy from Entergy Arkansas under the MSS-4 replacement tariff. This divestiture was effectuated initially through Entergy Mississippi’s purchases from Entergy Louisiana pursuant to a PPA governed by the MSS-4 replacement tariff, a tariff governing the sales of energy and capacity among the Utility operating companies as described in the System Energy global settlement with the LPSC and Entergy Louisiana. The MSS-4 replacement PPA to effectuate this divestiture was approved by the FERC in November 2024. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent, finding that it was just and reasonable for Entergy Mississippi to obtain Entergy Louisiana’s entitlements to Grand Gulf capacity and energy and that Entergy Mississippi should be allowed to recover the costs associated with the transfer of such entitlements to Grand Gulf capacity and energy, as described above. The MPSC approved the MSS-4 replacement PPA, effective as of January 1, 2025. An amended Unit Power Sales Agreement became effective as of October 1, 2025, which removed Entergy Louisiana from the entitlement and responsibility to purchase power from Grand Gulf. Thus on October 1, 2025, the MSS-4 replacement PPA was terminated. See “Complaints Against System Energy - System Energy Settlement with the LPSC” in Note 2 to the financial statements for further details of the System Energy global settlement with the LPSC and Note 8 to the financial statements for discussion of the amendment to the Unit Power Sales Agreement.

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

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

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.

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 as of January 31, 2024. The calculation of the annual factor for the power management rider included a projected under-recovery balance of $47 million as of January 31, 2024. In January 2024 the MPSC approved the proposed energy cost factor and the proposed power management cost factor effective for February 2024 bills.

In June 2024 the MPSC approved the joint stipulation agreement between Entergy Mississippi and the Mississippi Public Utilities Staff for Entergy Mississippi’s 2024 formula rate plan filing. The 2024 formula rate

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

plan filing included the conclusion of the modified interim adjustments to Entergy Mississippi’s energy cost recovery rider and power management rider, which were approved in October 2022 and allowed Entergy Mississippi to recover certain under-collected fuel balances, effective for July 2024 bills. The stipulation provided for Entergy Mississippi to reduce its net energy cost factor. See “Retail Rate Proceedings - Filings with the MPSC (Entergy Mississippi) - Retail Rates - 2024 Formula Rate Plan Filing” in Note 2 to the financial statements for further discussion of the 2024 formula rate plan filing and the joint stipulation agreement.

In November 2024, 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 $144.6 million as of September 30, 2024. The calculation of the annual factor for the power management rider included a projected under-recovery balance of $60.1 million as of September 30, 2024. In January 2025 the MPSC approved a revised energy cost factor, effective for February 2025 bills, that did not reflect the fuel savings associated with Entergy Mississippi’s incremental increase in its share of capacity and energy in connection with Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, which was subject to the MPSC’s review at such time. In February 2025 the MPSC approved Entergy Mississippi’s notice of intent for Entergy Mississippi’s assumption of Entergy Louisiana’s entitlements to Grand Gulf capacity and energy, with associated fuel savings to be reflected in Entergy Mississippi’s energy cost recovery rider, effective for March 2025 bills. Additionally, in February 2025 the MPSC approved the proposed power management cost adjustment factor, effective for March 2025 bills.

In November 2025, 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 $21.5 million as of September 30, 2025. The calculation of the annual factor for the power management rider included a projected under-recovery balance of $9.3 million as of September 30, 2025. In January 2026 the MPSC approved the proposed energy cost factor effective for February 2026 bills. In January 2026 the MPSC also approved a power management cost factor effective for February 2026 bills, based on an under-recovery balance that was $4.8 million lower than the previously filed under-recovery balance, due to a rate mitigation adjustment that utilized, for the benefit of customers, certain liquidated damages payments received by Entergy Mississippi.

Storm Cost Recovery Filings with Retail Regulators

Prior to June 2024, Entergy Mississippi had 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 exceeded $15 million, the collection of the storm damage provision ceased until such time that the accumulated storm damage provision became less than $10 million. Entergy Mississippi’s storm damage provision balance had been less than $10 million since May 2019, and Entergy Mississippi had 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 exceeded $15 million, in anticipation of a subsequent filing by Entergy Mississippi in this proceeding. The storm damage provision 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.

Entergy Mississippi, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

In March 2024, Entergy Mississippi made a combined dual filing which included a notice of intent to make routine change in rates and schedules and a motion for determination relating to the above-described notice of storm escrow disbursement. The notice of intent proposed a new storm damage mitigation and restoration rider to supersede both the then-current storm damage rate schedule and the vegetation management rider schedule, in which the collection of both expenses would be combined. The proposal requested that the MPSC authorize Entergy Mississippi to collect approximately $5.2 million per month for vegetation management and a storm damage provision. Furthermore, if Entergy Mississippi’s accumulated vegetation management and storm damage provision balance were to exceed $70 million, collection under the storm damage mitigation and restoration rider would cease until such time that the accumulated vegetation management and storm damage provision would become less than $60 million.

The Mississippi Public Utilities Staff reviewed the storm-related costs submitted by Entergy Mississippi and found them prudent. In June 2024 the MPSC considered and unanimously granted the relief sought by Entergy Mississippi, including authorization to credit any remaining funds in the storm escrow account to Entergy Mississippi’s storm damage provision and to close the storm escrow account and approving the new storm damage mitigation and restoration rider. Entergy Mississippi’s storm escrow account was liquidated in July 2024, and the new combined storm damage mitigation and restoration rider became effective with the July 2024 billing cycle. Additionally, Entergy Mississippi made a compliance filing to cease billing under the existing vegetation management rider schedule as of the same billing cycle.

Industrial and Commercial Customers

Entergy Mississippi’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Mississippi responds by working with industrial and commercial customers to negotiate electric service contracts with competitive rates that match specific customer needs and load profiles. Additionally, cogeneration is an option available to a portion of Entergy Mississippi’s industrial customer base. Entergy Mississippi actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

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

Taxation and Uncertain Tax Positions

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 2026 Qualified Pension Cost	Impact on 2025 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$170	$5,879
Rate of return on plan assets	(0.25%)	$754	$—
Rate of increase in compensation	0.25%	$241	$1,317

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 2026 Postretirement Benefits Cost	Impact on 2025 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$92	$1,058
Health care cost trend	0.25%	$109	$588

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 2025 was $3.2 million, including $146 thousand in settlement costs. Entergy Mississippi anticipates 2026 qualified pension cost to be $2.6 million. Entergy Mississippi contributed $8.1 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $4 million, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026.

Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2025 was $3.9 million. Entergy Mississippi expects 2026 postretirement health care and life insurance benefit income of approximately $3.5 million. Entergy Mississippi contributed $223 thousand to its other postretirement plans in 2025 and estimates that 2026 contributions will be approximately $176 thousand.

Other Contingencies

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, 2025 and 2024, the related consolidated statements of income, cash flows and changes in equity (pages 402 through 406 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for 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 the likelihood of 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 refund 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 19, 2026

We have served as the Company’s auditor since 2001.


ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING REVENUES
Electric	$1,955,705	$1,764,593	$1,802,533

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	165,590	270,015	563,296
Purchased power	374,694	273,580	281,761
Other operation and maintenance	371,096	315,651	320,192
Taxes other than income taxes	181,195	166,195	150,921
Depreciation and amortization	273,301	270,483	262,624
Other regulatory charges (credits) - net	73,111	36,723	(111,376)
TOTAL	1,438,987	1,332,647	1,467,418

OPERATING INCOME	516,718	431,946	335,115

OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction	9,449	9,095	8,552
Interest and investment income	18,024	3,249	2,275
Miscellaneous - net	3,953	(11,157)	(13,231)
TOTAL	31,426	1,187	(2,404)

INTEREST EXPENSE
Interest expense	147,881	110,931	99,857
Allowance for borrowed funds used during construction	(3,566)	(3,520)	(3,479)
TOTAL	144,315	107,411	96,378

INCOME BEFORE INCOME TAXES	403,829	325,722	236,333

Income taxes	95,101	80,315	54,364

NET INCOME	308,728	245,407	181,969

Net loss attributable to noncontrolling interest	(3,136)	(10,551)	(10,302)

EARNINGS APPLICABLE TO MEMBER'S EQUITY	$311,864	$255,958	$192,271

See Notes to Financial Statements.


ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING ACTIVITIES
Net income	$308,728	$245,407	$181,969
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization	273,301	270,483	262,624
Deferred income taxes, tax credits, and non-current taxes accrued	43,273	43,245	28,990
Changes in assets and liabilities:
Receivables	(28,465)	7,221	3,627
Fuel inventory	(3,518)	1,233	(648)
Accounts payable	7,608	60,450	(41,101)
Taxes accrued	(15,804)	63,890	(9,771)
Interest accrued	7,800	(870)	3,329
Deferred fuel costs	(137,073)	(4,329)	273,856
Other working capital accounts	79,721	(32,138)	(23,813)
Provisions for estimated losses	4,364	7,719	1,972
Other regulatory assets	70,133	53,229	(59,616)
Other regulatory liabilities	74,631	17,985	(59,513)
Customer advances - non-current	25,000	—	—
Pension and other postretirement funded status	(20,644)	(33,506)	(49,223)
Other assets and liabilities	15,639	(564)	46,709
Net cash flow provided by operating activities	704,694	699,455	559,391
INVESTING ACTIVITIES
Construction expenditures	(1,457,803)	(699,690)	(562,118)
Allowance for equity funds used during construction	9,449	9,095	8,552
Payment for purchase of plant	—	—	(35,094)
Proceeds from sale of assets	14,469	818	—
Changes in money pool receivable - net	(12,204)	(15,218)	26,879
Receipts from storm reserve escrow account	—	736	34,493
Decrease (increase) in other investments	16	(960)	(690)
Net cash flow used in investing activities	(1,446,073)	(705,219)	(527,978)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	592,506	395,881	396,833
Retirement of long-term debt	—	(200,000)	(500,000)
Capital contributions from parent	265,500	—	—
Capital contributions from noncontrolling interest	—	—	25,708
Changes in money pool payable - net	—	(73,769)	73,769
Common equity distributions paid	—	(44,633)	(40,000)
Customer advances received for construction	167,731	111,990	23,609
Customer advances used for construction	(95,785)	(32,031)	(19,513)
Other	(2,782)	(2,611)	(2,168)
Net cash flow provided by (used in) financing activities	927,170	154,827	(41,762)
Net increase (decrease) in cash and cash equivalents	185,791	149,063	(10,349)
Cash and cash equivalents at beginning of period	155,693	6,630	16,979
Cash and cash equivalents at end of period	$341,484	$155,693	$6,630
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$118,634	$109,444	$93,961
Income taxes - net	$82,541	($14,170)	$50,869
Noncash investing activities:
Accrued construction expenditures	$272,321	$141,227	$16,342

See Notes to Financial Statements.


ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2025	2024
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$27	$184
Temporary cash investments	341,457	155,509
Total cash and cash equivalents	341,484	155,693
Accounts receivable:
Customer	115,813	97,609
Allowance for doubtful accounts	(3,509)	(2,172)
Associated companies	37,723	23,909
Other	20,641	25,148
Accrued unbilled revenues	90,235	75,740
Total accounts receivable	260,903	220,234
Deferred fuel costs	10,757	—
Fuel inventory - at average cost	18,481	14,963
Materials and supplies	112,082	113,256
Prepayments and other	36,911	19,764
TOTAL	780,618	523,910

OTHER PROPERTY AND INVESTMENTS
Non-utility property - at cost (less accumulated depreciation)	4,467	4,482

Other	864	880
TOTAL	5,331	5,362

UTILITY PLANT
Electric	8,366,079	7,860,409
Construction work in progress	1,396,075	487,273
TOTAL UTILITY PLANT	9,762,154	8,347,682
Less - accumulated depreciation and amortization	2,635,823	2,511,091
UTILITY PLANT - NET	7,126,331	5,836,591

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets	455,714	525,847
Other	108,480	97,260
TOTAL	564,194	623,107

TOTAL ASSETS	$8,476,474	$6,988,970

See Notes to Financial Statements.


ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2025	2024
	(In Thousands)

CURRENT LIABILITIES

Accounts payable:
Associated companies	$61,135	$58,087
Other	397,756	283,755
Customer deposits	97,875	94,009
Taxes accrued	163,220	179,024
Interest accrued	28,467	20,667
Deferred fuel costs	—	126,316
Customer advances	89,538	—
Other	23,678	20,720
TOTAL	861,669	782,578

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	926,734	870,116
Accumulated deferred investment tax credits	13,191	13,446
Regulatory liability for income taxes - net	170,902	180,851
Other regulatory liabilities	144,124	59,544
Customer advances	25,000	—
Asset retirement cost liabilities	26,538	25,110
Accumulated provisions	51,564	47,200

Long-term debt	3,021,324	2,427,073
Customer advances for construction	184,564	112,618
Other	67,648	61,446
TOTAL	4,631,589	3,797,404

Commitments and Contingencies

EQUITY
Member's equity	2,978,150	2,400,786
Noncontrolling interest	5,066	8,202
TOTAL	2,983,216	2,408,988

TOTAL LIABILITIES AND EQUITY	$8,476,474	$6,988,970

See Notes to Financial Statements.


ENTERGY MISSISSIPPI, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2025, 2024, and 2023

	Noncontrolling Interest	Member's Equity	Total
	(In Thousands)

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
Net income (loss)	(10,551)	255,958	245,407
Common equity distributions	—	(44,633)	(44,633)

Balance at December 31, 2024	$8,202	$2,400,786	$2,408,988
Net income (loss)	(3,136)	311,864	308,728

Capital contributions from parent	—	265,500	265,500
Balance at December 31, 2025	$5,066	$2,978,150	$2,983,216

See Notes to Financial Statements.

ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $34.6 million primarily due to a $78.5 million ($57.4 million net-of-tax) regulatory charge, recorded in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. Also contributing to the increase were lower other operation and maintenance expenses, lower taxes other than income taxes, and lower depreciation and amortization expenses. The increase was partially offset by a $12.8 million ($9.6 million net-of-tax) charge, recorded in third quarter 2025, to reflect the write-off of retained natural gas plant assets that were not included in the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025, and which will not be recovered, higher interest expense, and lower other income. See Note 3 to the financial statements for discussion of the April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:


			Amount
			(In Millions)
2024 operating revenues			$810.6
Fuel, rider, and other revenues that do not significantly affect net income			11.3
Effect of sale of natural gas distribution business			(45.5)
Volume/weather			(2.8)
Retail electric price			(1.4)

2025 operating revenues			$772.2

Entergy New Orleans’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The effect of sale of natural gas distribution business variance represents the decrease in operating revenues resulting from the absence of natural gas revenues following the sale of the natural gas distribution business on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.

The volume/weather variance is primarily due to a decrease in weather-adjusted residential usage and a decrease in commercial usage, partially offset by the effect of more favorable weather on residential sales.

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

The retail electric price variance is primarily due to a decrease in formula rate plan rates effective September 2025 in accordance with the terms of the 2025 formula rate plan filing, partially offset by an increase in formula rate plan rates effective September 2024 in accordance with the terms of the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the formula rate plan filings.

Total electric energy sales for Entergy New Orleans for the years ended December 31, 2025 and 2024 are as follows:


	2025	2024	% Change
	(GWh)
Residential	2,370	2,341	1
Commercial	2,046	2,094	(2)
Industrial	384	369	4
Governmental	778	793	(2)
Total retail	5,578	5,597	—
Sales for resale:
Associated companies	8	—	—
Non-associated companies	1,696	2,123	(20)
Total	7,282	7,720	(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 decreased primarily due to:

a decrease of $6.6 million in gas operation expenses resulting from the absence of expenses during the last six months of 2025 and a $2.7 million gain, recorded in 2025, both as a result of the sale of the natural gas distribution business on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025;
contract costs of $3.3 million in 2024 related to operational performance, customer service, and organizational health initiatives;
$1.8 million in costs recognized in 2024 related to credits provided to customers as part of the rate mitigation plan approved in the settlement of the 2023 formula rate plan filing. See Note 2 to the financial statements for discussion of the 2023 formula rate plan filing; and
a decrease of $1.6 million in loss provisions.

The decrease was partially offset by an increase of $2.3 million in energy efficiency expenses primarily due to higher energy efficiency costs, partially offset by the timing of recovery from customers.

Asset write-offs includes a $12.8 million charge, recorded in third quarter 2025, to reflect the write-off of retained natural gas plant assets that were not included in the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025, and which will not be recovered. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.

Taxes other than income taxes decreased primarily due to decreases in local franchise fees as a result of lower retail revenues in 2025 as compared to 2024, including decreased natural gas revenues resulting from the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025, and decreases in ad valorem taxes resulting from lower assessments. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Depreciation and amortization expenses decreased primarily due to the absence of depreciation and amortization expenses associated with natural gas plant in service following the sale of the natural gas distribution business on July 1, 2025, partially offset by additions to plant in service. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025.

Other regulatory charges (credits) - net includes a regulatory charge of $78.5 million, recorded in first quarter 2024, primarily to reflect a settlement in principle between Entergy New Orleans and the City Council in April 2024 for additional sharing with customers of income tax benefits from the resolution of the 2016-2018 IRS audit. See Note 3 to the financial statements for discussion of the April 2024 settlement in principle and discussion of the resolution of the 2016-2018 IRS audit.

Other income decreased primarily due to the deferral of certain other postretirement benefit expense credits, effective September 2024, in accordance with the terms of the 2024 formula rate plan filing. See Note 2 to the financial statements for discussion of the 2024 formula rate plan filing and Note 11 to the financial statements for discussion of the other postretirement benefits accounting treatment.

Interest expense increased primarily due to an increase of $8 million in carrying costs on regulatory liability balances, partially offset by lower interest accrued on customer deposits.

The effective income tax rates were 23.9% for 2025 and 15.2% for 2024. 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.

2024 Compared to 2023

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, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.

Income Tax Legislation and Regulation

Sale of Natural Gas Distribution Business

See the “Dispositions - Natural Gas Distribution Businesses” section in Note 14 to the financial statements for discussion of the sale of the Entergy New Orleans natural gas distribution business.

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, 2025, 2024, and 2023 were as follows:


	2025	2024	2023
	(In Thousands)
Cash and cash equivalents at beginning of period	$31,777	$26	$4,464

Net cash provided by (used in):
Operating activities	183,699	286,729	202,956
Investing activities	115,385	(163,481)	(18,802)
Financing activities	(220,597)	(91,497)	(188,592)
Net increase (decrease) in cash and cash equivalents	78,487	31,751	(4,438)

Cash and cash equivalents at end of period	$110,264	$31,777	$26

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities decreased $103 million in 2025 primarily due to:

the receipt of $98.1 million in settlement proceeds in 2024 as a result of the System Energy settlement with the City Council. See Note 2 to the financial statements for discussion of the System Energy settlement with the City Council;
the timing of payments to vendors; and
income tax payments of $10.1 million in 2025 compared to income tax refunds of $17.9 million in 2024. Entergy New Orleans made income tax payments in 2025 primarily related to estimated state income taxes and in accordance with Entergy’s tax allocation agreement. Entergy New Orleans received income tax refunds in 2024 primarily in accordance with Entergy’s tax allocation agreement.

The decrease was partially offset by higher collections from customers and the receipt of $59.9 million in payments from affiliates in 2025 in accordance with the Unit Power Sales Agreement and the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by affiliates to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits.

Investing Activities

Entergy New Orleans’s investing activities provided $115.4 million of cash in 2025 compared to using $163.5 million of cash in 2024 primarily due to the following activity:

$283.9 million in proceeds from the sale of the natural gas distribution business on July 1, 2025. See Note 14 to the financial statements for discussion of the sale of Entergy New Orleans’s natural gas distribution business on July 1, 2025;
an increase of $20.3 million in non-nuclear generation construction expenditures primarily due to a higher scope of work performed during plant outages in 2025 as compared to 2024; and
the receipt of $13.1 million from the storm reserve escrow account in 2025.

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Financing Activities

Net cash flow used in financing activities increased $129.1 million in 2025 primarily due to:

the issuances of $65 million of 6.41% Series mortgage bonds, $50 million of 6.54% Series mortgage bonds, and $35 million of 6.25% Series mortgage bonds, each in May 2024;
the repayment, at maturity, of $78 million of 3.00% Series mortgage bonds in March 2025; and
an increase of $15 million in common equity distributions paid in 2025 in order to maintain Entergy New Orleans’s capital structure.

The increase was partially offset by the repayment, at maturity, of an $85 million unsecured term loan in June 2024 and money pool activity.

Decreases in Entergy New Orleans’s payable to the money pool are a use of cash flow, and Entergy New Orleans’s payable to the money pool decreased $21.7 million in 2024. 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 more details on long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy New Orleans’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.

Capital Structure

Entergy New Orleans’s debt to capital ratio is shown in the following table.


	December 31, 2025		December 31, 2024
Debt to capital	52.1	%	51.5	%
Effect of subtracting cash	(4.6	%)	(1.1	%)
Net debt to net capital, excluding securitization bonds (non-GAAP) (a)	47.5	%	50.4	%

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, finance lease obligations, long-term debt, including the currently maturing portion, and the long-term payable due to an associated company. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The net debt to net capital ratio is a non-GAAP measure. Entergy New Orleans 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 New Orleans’s financial condition. Entergy New Orleans 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 New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a distribution, to the extent funds are legally available to do so, or

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce distributions, or both, to maintain its capital structure. In addition, in certain infrequent circumstances, such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced distributions, Entergy New Orleans may receive equity contributions to maintain its capital structure.

Uses of Capital

Entergy New Orleans requires capital resources for:

construction and other capital investments;
working capital purposes, including the financing of fuel and purchased power costs;
debt maturities or retirements; and
distribution and interest payments.

Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.


	2026	2027	2028	2029
	(In Millions)
Planned construction and capital investment:
Generation	$15	$10	$50	$20
Transmission	10	15	15	30
Distribution	185	125	110	150
Utility Support	15	10	10	15
Total	$225	$160	$185	$215

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes distribution and Utility support spending to improve reliability, resilience, and customer experience; transmission spending to improve reliability and resilience; 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, governmental actions, including the trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy New Orleans’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy New Orleans’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect Entergy New Orleans’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy New Orleans’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.

Entergy New Orleans has incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on its current and planned capital projects. Entergy New Orleans is not able to predict any

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments).


	2026	2027	2028	2029-2030	After 2030
	(In Millions)
Long-term debt (a)	$116	$29	$29	$90	$846
Operating leases (b)	$2	$2	$2	$2	$1
Finance leases (b)	$1	$1	$1	$1	$1

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

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

Other Obligations

Entergy New Orleans currently expects to contribute approximately $3.3 million to its qualified pension plans and approximately $336 thousand to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026. 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 New Orleans has $14.8 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 New Orleans enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy New Orleans has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations. See Note 8 to the financial statements for discussion of Entergy New Orleans’s obligations under the Unit Power Sales Agreement.

As a wholly-owned subsidiary of Entergy Utility Holding Company, LLC, Entergy New Orleans pays distributions from its earnings at a percentage determined monthly.

Resilience and Grid Hardening

In October 2021 the City Council passed a resolution and order establishing a docket and procedural schedule with respect to system resiliency and storm hardening. In July 2022, Entergy New Orleans filed with the City Council a response identifying a preliminary plan for storm hardening and resiliency projects, including microgrids, to be implemented over ten years at an approximate cost of $1.5 billion. In February 2023 the City Council approved a revised procedural schedule requiring Entergy New Orleans to make a filing in April 2023 containing a narrowed list of proposed hardening projects. In April 2023, Entergy New Orleans filed the required application and supporting testimony seeking City Council approval of the first phase (five years and $559 million) of a ten-year infrastructure hardening plan totaling approximately $1 billion. Entergy New Orleans also sought, among other relief, City Council approval of a resilience and storm hardening cost recovery rider to recover from customers the costs of the infrastructure hardening plan. In February 2024 the City Council approved a resolution authorizing Entergy New Orleans to implement a resilience project to be partially funded by $55 million of matching funding through the DOE’s Grid Resilience and Innovation Partnerships program. The resolution also

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

required Entergy New Orleans to submit, no later than July 2024, a revised resilience plan consisting of projects over a three-year period. In March 2024, Entergy New Orleans filed with the City Council for approval the requested three-year resilience plan, which included $168 million in hardening projects. The three-year resilience plan was to be in addition to the previously authorized resilience project to be partially funded by the DOE’s Grid Resilience and Innovation Partnerships program. In October 2024 the City Council approved a resolution authorizing a two-year resilience plan totaling $100 million and approved the requested resilience and storm hardening cost recovery rider. In December 2024, Entergy New Orleans notified the City Council of the subset of hardening projects from the revised three-year resilience plan to be included in the two-year resilience plan. Entergy New Orleans implemented the approved resilience and storm hardening cost recovery rider effective with the first billing cycle of January 2025. In December 2025, the City Council issued a resolution establishing certain metrics and reporting requirements for the approved hardening projects. Also in December 2025, Entergy New Orleans filed an application and supporting testimony seeking the City Council’s approval of the second phase of its infrastructure hardening plan totaling approximately $400 million over a five-year period (2027 to 2031). Entergy New Orleans also sought, among other relief, the City Council’s approval to continue to use the resilience and storm hardening cost recovery rider to recover from customers the costs of the plan. Entergy New Orleans requested the City Council approve the application by October 2026.

Sources of Capital

Entergy New Orleans’s sources to meet its capital requirements include:

internally generated funds;
cash on hand;
the Entergy system money pool;
storm reserve escrow accounts;
debt and preferred membership interest issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
capital contributions; and
bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy New Orleans expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

All debt and common and preferred membership interest issuances by Entergy New Orleans require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indenture and other agreements. Entergy New Orleans has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy New Orleans’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.


2025	2024	2023	2022
(In Thousands)
$9,009	$3,146	($21,651)	$147,254

See Note 4 to the financial statements for a description of the money pool.

Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in June 2027. The credit facility includes fronting commitments for the issuance of letters of credit against $10 million of the

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

borrowing capacity of the facility. As of December 31, 2025, there were no cash borrowings and no letters of credit outstanding under the credit facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations to MISO. As of December 31, 2025, a $0.5 million letter of credit was outstanding under Entergy New Orleans’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy New Orleans obtained authorization from the FERC through January 2027 for short-term borrowings not to exceed an aggregate amount of $150 million at any time outstanding and long-term borrowings and securities issuances. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized not only by the FERC, but also by the City Council, and the current City Council authorization extends through December 2027.

State and Local Rate Regulation

The rates that Entergy New Orleans charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.

Retail Rates

2023 Formula Rate Plan Filing

In April 2023, Entergy New Orleans submitted to the City Council its formula rate plan 2022 test year filing. The 2022 test year evaluation report produced an electric earned return on equity of 7.34% and a gas earned return on equity of 3.52% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $25.6 million rate increase based on the formula set by the City Council in the 2018 rate case. The formula would result in an increase in authorized electric revenues of $17.4 million and an increase in authorized gas revenues of $8.2 million. Entergy New Orleans also sought to commence collecting $3.4 million in electric revenues that were previously approved by the City Council for collection through the formula rate plan. In July 2023, Entergy New Orleans filed a report to decrease its requested formula rate plan revenues by approximately $0.5 million to account for minor errors discovered after the filing. The City Council advisors issued a report seeking a reduction in the requested formula rate plan revenues of approximately $8.3 million, combined for electric and gas, due to alleged errors. The City Council advisors proposed additional rate mitigation in the amount of $12 million through offsets to the formula rate plan rate increase by certain regulatory liabilities. In September 2023 the City Council approved an agreement to settle the 2023 formula rate plan filing. Effective with the first billing cycle of September 2023, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The agreement provided for a total increase in electric revenues of $10.5 million and a total increase in gas revenues of $6.9 million. The agreement also provided for a minor storm accrual of $0.5 million per year and the distribution of $8.9 million of then-held customer credits to implement the City Council advisors’ mitigation recommendations.

Request for Extension and Modification of Formula Rate Plan

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. In October 2023 the City Council granted Entergy New Orleans’s request for an extension, subject to minor modifications which included a 55% equity ratio for rate setting purposes.

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

2024 Formula Rate Plan Filing

In April 2024, Entergy New Orleans submitted to the City Council its formula rate plan 2023 test year filing. Without the requested rate change in 2024, the 2023 test year evaluation report produced an electric earned return on equity of 8.66% and a gas earned return on equity of 5.87% compared to the authorized return on equity for each of 9.35%. Entergy New Orleans sought approval of a $12.6 million rate increase based on the formula set by the City Council in the 2018 rate case and approved again by the City Council in 2023. The formula would result in an increase in authorized electric revenues of $7.0 million and an increase in authorized gas revenues of $5.6 million. Following City Council review, the City Council’s advisors issued a report in July 2024 seeking a reduction in Entergy New Orleans’s requested formula rate plan revenues in an aggregate amount of approximately $1.6 million for electric and gas together due to alleged errors. Effective with the first billing cycle of September 2024, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate plan implementation. The total formula rate plan increase implemented was $11.2 million, which included an increase of $5.8 million in electric revenues and an increase of $5.4 million in gas revenues.

2025 Formula Rate Plan Filing

In April 2025, Entergy New Orleans submitted to the City Council its formula rate plan 2024 test year filing. The 2024 evaluation report produced an electric earned return on equity of 10.98% compared to the authorized return on equity of 9.35%. Without adjustments, this would have resulted in a decrease in electric rates of $13.8 million. The decrease in electric rates was driven by the realignment of regulatory liabilities into the formula from a separate rate mechanism, partially offset by the cost of known and measurable electric capital additions. The filing also commenced the previously authorized recovery of certain regulatory costs and requested a revenue-neutral recovery to offset a proposed reduction in bill payment late fees. Taking into account these proposed adjustments, the filing presented a decrease in authorized electric revenues of $8.6 million. The City Council’s advisors issued a report in July 2025 seeking a reduction in Entergy New Orleans’s requested electric formula rate plan revenues of approximately $7.2 million due to certain proposed cost realignments and disallowances, of which $4.1 million was associated with Entergy New Orleans’s proposed implementation, on a revenue neutral basis, of a proposed reduction in customer late fees. The City Council’s advisors also proposed rate mitigation in the amount of $4.4 million through offsets to the formula rate plan funded by certain regulatory liabilities. In August 2025 the City Council approved an agreement to settle the 2025 formula rate plan filing. Effective with the first billing cycle of September 2025, Entergy New Orleans implemented rates reflecting an amount agreed upon by Entergy New Orleans and the City Council, per the approved process for formula rate implementation. The electric formula rate plan decrease implemented was $19.2 million.

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.

Distributed Energy Resources Program

In October 2024 the City Council opened a docket to evaluate potential opportunities to increase the availability of distributed energy resources, battery storage, and related facilities in New Orleans. In December 2025 the City Council issued a resolution establishing a distributed energy resources program to be implemented and operated under the existing Energy Smart program, with $28 million in customer incentives available through credits funded by credits from the System Energy settlement with the City Council. See “Complaints Against System Energy - System Energy Settlement with the City Council” in Note 2 to the financial statements for discussion of the System Energy settlement with the City Council.

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Federal Regulation

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy New Orleans’s financial statements in conformity with 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 New Orleans’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

Entergy New Orleans’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are 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.

Entergy New Orleans, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).


Actuarial Assumption	Change in Assumption	Impact on 2026 Qualified Pension Cost	Impact on 2025 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$64	$2,147
Rate of return on plan assets	(0.25%)	$247	$—
Rate of increase in compensation	0.25%	$98	$343

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 2026 Postretirement Benefits Cost	Impact on 2025 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$8	$353
Health care cost trend	0.25%	$14	$179

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy New Orleans in 2025 was $6.4 million, including $6.2 million in settlement costs. Entergy New Orleans anticipates 2026 qualified pension cost to be $1 million. Entergy New Orleans contributed $5 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $3.3 million, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026.

Total postretirement health care and life insurance benefit costs for Entergy New Orleans in 2025 was $12.3 million, including $1.6 million in settlement and curtailment credits. Entergy New Orleans expects 2026 postretirement health care and life insurance benefit income of approximately $4.7 million. Entergy New Orleans contributed $97 thousand to its other postretirement plans in 2025 and estimates 2026 contributions will be approximately $336 thousand.

Other Contingencies

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 New Orleans, LLC and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy New Orleans, LLC and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, cash flows, and changes in member’s equity (pages 421 through 426 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Rate and Regulatory Matters — Entergy New Orleans, LLC and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Council of the City of New Orleans, Louisiana (the “City Council”), which has jurisdiction with respect to the rates of electric companies in the City of New Orleans, Louisiana, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the City Council and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the City Council and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the 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 the likelihood of refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the City Council 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 City Council 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 City Council 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 City Council’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 City Council and the FERC and orders issued, and considered the filings with the City Council and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions*.*
We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or refund 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 19, 2026

We have served as the Company’s auditor since 2001.


ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING REVENUES
Electric	$703,893	$708,354	$737,974
Natural gas	68,321	102,210	105,959
TOTAL	772,214	810,564	843,933

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	92,621	99,055	122,400
Purchased power	271,170	252,863	268,478
Other operation and maintenance	157,415	172,101	167,719
Asset write-offs	12,795	—	—
Taxes other than income taxes	57,282	60,476	62,979
Depreciation and amortization	81,830	84,937	81,282
Other regulatory charges (credits) - net	(12,654)	85,136	69,211
TOTAL	660,459	754,568	772,069

OPERATING INCOME	111,755	55,996	71,864

OTHER INCOME
Allowance for equity funds used during construction	1,857	2,118	1,470
Interest and investment income	2,650	2,144	7,154
Miscellaneous - net	(3,695)	(115)	(4,119)
TOTAL	812	4,147	4,505

INTEREST EXPENSE
Interest expense	47,322	42,337	38,118
Allowance for borrowed funds used during construction	(1,021)	(883)	(714)
TOTAL	46,301	41,454	37,404

INCOME BEFORE INCOME TAXES	66,266	18,689	38,965

Income taxes	15,855	2,842	(189,973)

NET INCOME	$50,411	$15,847	$228,938

See Notes to Financial Statements.

(Page left blank intentionally)


ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING ACTIVITIES
Net income	$50,411	$15,847	$228,938
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization	81,830	84,937	81,282
Deferred income taxes, tax credits, and non-current taxes accrued	(1,040)	12,271	(191,326)
Asset write-offs	12,795	—	—
Changes in assets and liabilities:
Receivables	18,909	(6,955)	29,944
Fuel inventory	3,295	(813)	2,574
Accounts payable	(19,309)	(4,864)	(11,924)
Prepaid taxes and taxes accrued	7,550	10,360	(11,882)
Interest accrued	(1,842)	137	454
Deferred fuel costs	7,110	2,247	4,005
Other working capital accounts	(2,913)	192	(9,184)
Provisions for estimated losses	(11,360)	2,169	1,076
Other regulatory assets	47,257	25,424	19,745
Other regulatory liabilities	26,316	175,808	66,022

Pension and other postretirement funded status	5,711	(21,638)	(16,371)
Other assets and liabilities	(41,021)	(8,393)	9,603
Net cash flow provided by operating activities	183,699	286,729	202,956
INVESTING ACTIVITIES
Construction expenditures	(176,058)	(158,257)	(164,279)
Allowance for equity funds used during construction	1,857	2,118	1,470
Changes in money pool receivable - net	(5,863)	(3,146)	147,254
Payments to storm reserve escrow account	(3,194)	(5,011)	(3,731)
Receipts from storm reserve escrow account	13,114	—	—
Proceeds from sale of business	283,918	—	—
Changes in securitization account	1,611	815	(191)
Decrease in other investments	—	—	675
Net cash flow provided by (used in) investing activities	115,385	(163,481)	(18,802)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	79,678	148,913	14,610
Retirement of long-term debt	(158,004)	(91,245)	(112,525)
Repayment of long-term payable due to associated company	(1,140)	(1,275)	(1,306)
Contributions from customer for construction	—	—	15,000
Changes in money pool payable - net	—	(21,651)	21,651
Common equity distributions paid	(140,000)	(125,000)	(125,000)
Other	(1,131)	(1,239)	(1,022)
Net cash flow used in financing activities	(220,597)	(91,497)	(188,592)
Net increase (decrease) in cash and cash equivalents	78,487	31,751	(4,438)
Cash and cash equivalents at beginning of period	31,777	26	4,464
Cash and cash equivalents at end of period	$110,264	$31,777	$26
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$35,205	$40,312	$36,263
Income taxes - net	$10,097	($17,903)	$14,120
Noncash investing activities:
Accrued construction expenditures	$12,721	$2,865	$7,068

See Notes to Financial Statements.


ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2025	2024
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$26	$374
Temporary cash investments	110,238	31,403
Total cash and cash equivalents	110,264	31,777
Securitization recovery trust account	—	1,611
Accounts receivable:
Customer	55,972	65,731
Allowance for doubtful accounts	(3,845)	(6,735)
Associated companies	10,459	5,844
Other	3,668	9,467
Accrued unbilled revenues	28,303	33,296
Total accounts receivable	94,557	107,603

Fuel inventory - at average cost	816	320
Materials and supplies	30,539	25,516

Current assets held for sale	—	13,100
Prepayments and other	12,992	12,128
TOTAL	249,168	192,055

OTHER PROPERTY AND INVESTMENTS

Storm reserve escrow account	73,822	83,742
Other	9,485	832
TOTAL	83,307	84,574

UTILITY PLANT
Electric	2,267,691	2,160,165
Natural gas	—	43,279
Construction work in progress	43,055	18,269
TOTAL UTILITY PLANT	2,310,746	2,221,713
Less - accumulated depreciation and amortization	778,401	768,305
UTILITY PLANT - NET	1,532,345	1,453,408

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets	109,690	133,261
Deferred fuel costs	4,080	4,080
Non-current assets held for sale	—	284,738
Other	80,090	71,037
TOTAL	193,860	493,116

TOTAL ASSETS	$2,058,680	$2,223,153

See Notes to Financial Statements.


ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2025	2024
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$85,000	$78,000
Payable due to associated company	720	1,140
Accounts payable:
Associated companies	47,709	45,479
Other	32,067	43,750
Customer deposits	30,632	28,834
Taxes accrued	16,336	8,786
Interest accrued	6,829	8,671
Deferred fuel costs	3,209	980
Other	10,659	14,427
TOTAL	233,161	230,067

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	201,345	201,541
Accumulated deferred investment tax credits	15,425	15,617
Regulatory liability for income taxes - net	15,656	15,000
Other regulatory liabilities	312,962	260,312
Accumulated provisions	78,933	90,293
Long-term debt	565,985	650,463
Long-term payable due to associated company	5,144	5,864
Other	22,057	56,395
TOTAL	1,217,507	1,295,485

Commitments and Contingencies

EQUITY
Member's equity	608,012	697,601
TOTAL	608,012	697,601

TOTAL LIABILITIES AND EQUITY	$2,058,680	$2,223,153

See Notes to Financial Statements.


ENTERGY NEW ORLEANS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
For the Years Ended December 31, 2025, 2024, and 2023

						Member’s Equity
						(In Thousands)

Balance at December 31, 2022						$702,816
Net income						228,938
Common equity distributions						(125,000)
Balance at December 31, 2023						$806,754
Net income						15,847
Common equity distributions						(125,000)
Balance at December 31, 2024						$697,601
Net income						50,411
Common equity distributions						(140,000)
Balance at December 31, 2025						$608,012

See Notes to Financial Statements.

ENTERGY TEXAS, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

2025 Compared to 2024

Net Income

Net income increased $40.5 million primarily due to higher retail electric price, higher volume/weather, and higher other income, partially offset by higher purchased power costs related to the procurement of capacity through MISO’s annual planning resource auction, higher interest expense, higher other operation and maintenance expenses, higher taxes other than income taxes, and higher depreciation and amortization expenses.

Operating Revenues

Following is an analysis of the change in operating revenues comparing 2025 to 2024:


			Amount
			(In Millions)
2024 operating revenues			$2,050.2
Fuel, rider, and other revenues that do not significantly affect net income			(37.7)
Retail electric price			66.5
Volume/weather			48.6
2025 operating revenues			$2,127.6

Entergy Texas’s results include revenues from rate mechanisms designed to recover fuel, purchased power, and other costs such that the revenues and expenses associated with these items generally offset and do not affect net income. “Fuel, rider, and other revenues that do not significantly affect net income” includes the revenue variance associated with these items.

The retail electric price variance is primarily due to the implementation of the distribution cost recovery factor rider effective with the first billing cycle in October 2024 and increases in the distribution cost recovery factor rider effective in December 2024 and June 2025. See Note 2 to the financial statements for discussion of the distribution cost recovery factor rider filings.

The volume/weather variance is primarily due to an increase in industrial usage and the effect of more favorable weather on residential sales. The increase in industrial usage is primarily due to an increase in demand from large industrial customers, primarily in the transportation, petroleum refining, wood products, and primary metals industries.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Total electric energy sales for Entergy Texas for the years ended December 31, 2025 and 2024 are as follows:


	2025	2024	% Change
	(GWh)
Residential	6,991	6,597	6
Commercial	5,035	4,879	3
Industrial	9,825	9,457	4
Governmental	271	269	1
Total retail	22,122	21,202	4
Sales for resale:
Non-associated companies	402	687	(41)
Total	22,524	21,889	3

See Note 19 to the financial statements for additional discussion of Entergy Texas’s operating revenues.

Other Income Statement Variances

Purchased power includes an increase in 2025 of $33.8 million in costs related to the procurement of capacity through MISO’s annual planning resource auction, including the effect of a significant increase in MISO’s seasonal auction clearing price, due in part to the implementation of a reliability-based demand curve, for capacity transactions during the summer months. Although Entergy Texas does not have the ability to recover its MISO capacity costs incurred to date beyond the level included in base rates, in June 2025, Texas legislation established a capacity cost recovery rider mechanism that would allow for the recovery of costs related to the procurement of capacity through MISO’s annual planning resource auction outside of base rates through a rider that is updated annually. Entergy Texas plans in second quarter 2026 to file for such a rider to recover future capacity procurement costs at the earliest opportunity.

Other operation and maintenance expenses increased primarily due to:

an increase of $8.0 million in bad debt expense;
an increase of $7.9 million in power delivery expenses primarily due to higher vegetation maintenance costs;
an increase of $3.7 million in loss provisions;
an increase of $1.8 million in transmission costs allocated by MISO;
an increase of $1.7 million in insurance expense primarily due to higher premiums in 2025 as compared to 2024;
an increase of $1.6 million in energy efficiency costs primarily due to the timing of recovery from customers; and
several individually insignificant items.

The increase was partially offset by:

contract costs of $8.1 million in 2024 related to operational performance, customer service, and organizational health initiatives;
a decrease of $6.9 million in non-nuclear generation expenses primarily due to a lower scope of work, including during plant outages, in 2025 as compared to 2024; and
a decrease of $1.8 million in storm damage provisions.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Taxes other than income taxes increased primarily due to increases in ad valorem taxes resulting from higher assessments.

Depreciation and amortization expenses decreased primarily due to the recognition of $27.6 million in depreciation expense in 2024 for the 2022 base rate case relate back period, effective over six months beginning January 2024. The recognition of depreciation expense for the relate back period was effective over the same period as collections from the relate back surcharge rider and resulted in no effect on net income. See Note 2 to the financial statements for discussion of the 2022 base rate case. The decrease was partially offset by additions to plant in service.

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 2025, including the Legend Power Station project, the Orange County Advanced Power Station project, and the Lone Star Power Station project, partially offset by lower interest earned on money pool investments.

Interest expense increased primarily due to the issuance of $500 million of 5.25% Series mortgage bonds in February 2025 and the issuance of $350 million of 5.55% Series mortgage bonds in August 2024, partially offset by an increase in the allowance for borrowed funds used during construction due to higher construction work in progress in 2025, including the Orange County Advanced Power Station project, the Legend Power Station project, and the Lone Star Power Station project.

The effective income tax rates were 16.4% for 2025 and 18.3% for 2024. 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.

Income Tax Legislation and Regulation

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:


	2025	2024	2023
	(In Thousands)
Cash and cash equivalents at beginning of period	$184,997	$21,986	$3,497

Net cash provided by (used in):
Operating activities	627,913	823,649	641,691
Investing activities	(1,241,307)	(928,418)	(1,125,948)
Financing activities	703,505	267,780	502,746
Net increase in cash and cash equivalents	90,111	163,011	18,489

Cash and cash equivalents at end of period	$275,108	$184,997	$21,986

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities decreased $195.7 million in 2025 primarily due to the timing of recovery of fuel and purchased power costs and higher fuel and purchased power payments, an increase of $32.7 million in interest paid, and the timing of payments to vendors. The decrease was partially offset by the receipt of $45.6 million in payments from affiliates in 2025 in accordance with the MSS-4 replacement tariff related to the transfer of 2024 nuclear production tax credits by affiliates to third parties in 2025 and a decrease of $19 million in storm spending primarily due to Hurricane Beryl restoration efforts in 2024. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery. See Note 3 to the financial statements for discussion of the nuclear production tax credits.

Investing Activities

Net cash flow used in investing activities increased $312.9 million in 2025 primarily due to an increase of $514.4 million in non-nuclear generation construction expenditures primarily due to higher spending on the Legend Power Station project, the Lone Star Power Station project, and the Orange County Advanced Power Station project and money pool activity. The increase was partially offset by:

the receipt of $358.8 million in proceeds from the sale of assets related to the Legend Power Station project in 2025. See Note 8 to the financial statements for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station;
a decrease of $53.2 million in transmission construction expenditures primarily due to decreased spending on various transmission projects in 2025;
proceeds of $41.4 million received in 2025 from the transfer of assets related to the Segno Solar and Votaw Solar facilities from Entergy Texas to Entergy Louisiana. See “Uses and Sources of Capital - Segno Solar and Votaw Solar” below for discussion of the facilities and transfer; and
a decrease of $23.0 million in distribution construction expenditures primarily due to lower capital expenditures for storm restoration in 2025, partially offset by higher capital expenditures as a result of increased development in Entergy Texas’s service area. The decrease in storm restoration expenditures is primarily due to Hurricane Beryl restoration efforts in 2024.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Increases in Entergy Texas’s receivable from the money pool are a use of cash flow, and Entergy Texas’s receivable from the money pool increased $4.0 million in 2025 compared to decreasing by $299.4 million in 2024. 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 increased $435.7 million in 2025 primarily due to:

the issuance of $500 million of 5.25% Series mortgage bonds in February 2025;
a capital contribution of $225 million received from Entergy Corporation in 2025 in order to maintain Entergy Texas’s capital structure and in anticipation of various capital expenditures; and
the payment of $69 million of common stock dividends in 2024. No common stock dividends were paid in 2025 in order to maintain Entergy Texas’s capital structure.

The increase was partially offset by a decrease of $20.9 million in advance payments from customers for construction related to transmission, distribution, and generator interconnection agreements and the issuance of $350 million of 5.55% Series mortgage bonds in August 2024.

See Note 5 to the financial statements for additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of Entergy Texas’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.

Capital Structure

Entergy Texas’s debt to capital ratio is shown in the following table.


	December 31, 2025		December 31, 2024
Debt to capital	50.9	%	51.6	%
Effect of excluding securitization bonds	(1.4	%)	(1.7	%)
Debt to capital, excluding securitization bonds (non-GAAP) (a)	49.5	%	49.9	%
Effect of subtracting cash	(1.9	%)	(1.5	%)
Net debt to net capital, excluding securitization bonds (non-GAAP) (a)	47.6	%	48.4	%

(a)Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas.

Net debt consists of debt less cash and cash equivalents. Debt consists of finance lease obligations and long-term debt, including the currently maturing portion. Capital consists of debt and equity. Net capital consists of capital less cash and cash equivalents. The debt to capital ratio excluding securitization bonds and net debt to net capital ratio excluding securitization bonds are non-GAAP measures. Entergy Texas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas’s financial condition

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Texas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, to the extent funds are legally available to do so, or both, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, Entergy Texas may receive equity contributions to maintain its capital structure for certain circumstances such as financing of large transactions that would materially alter the capital structure if financed entirely with debt and reduced dividends.

Uses of Capital

Entergy Texas requires capital resources for:

construction and other capital investments;
debt maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.

Following are the amounts of Entergy Texas’s planned construction and other capital investments.


	2026	2027	2028	2029
	(In Millions)
Planned construction and capital investment:
Generation	$685	$285	$1,435	$80
Transmission	385	615	680	645
Distribution	525	445	335	340
Utility Support	35	30	45	35
Total	$1,630	$1,375	$2,495	$1,100

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes investments in generation projects to modernize, decarbonize, expand, and diversify Entergy Texas’s portfolio, including Orange County Advanced Power Station, Lone Star Power Station, and Legend Power Station; 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, governmental actions, including trade-related governmental actions, such as tariffs and other measures, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies. Entergy Texas is not able to predict the effect of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact Entergy Texas’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with Entergy Texas’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified,

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

skilled labor, or raw materials sourcing disruptions which may affect Entergy Texas’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect Entergy Texas’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.

Entergy Texas has incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on its current and planned capital projects. Entergy Texas is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as loans, grants, guarantees, and other subsidiaries, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments).


	2026	2027	2028	2029-2030	After 2030
	(In Millions)
Long-term debt (a)	$316	$334	$179	$636	$5,415
Operating leases (b)	$8	$7	$6	$6	$1
Finance leases (b)	$3	$3	$2	$3	$2

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

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

Other Obligations

Entergy Texas currently expects to contribute approximately $5.9 million to its qualified pension plans and approximately $149 thousand to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026. 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 Texas has $103.5 million of unrecognized tax benefits net of unused tax attributes plus interest and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

See below for discussion of the build-to-suit lease arrangement for the Legend Power Station.

In addition, Entergy Texas enters into fuel and purchased power agreements that contain minimum purchase obligations. Entergy Texas has rate mechanisms in place to recover fuel, purchased power, and associated costs incurred under these purchase obligations.

As a subsidiary, Entergy Texas dividends its earnings to Entergy Corporation at a percentage determined monthly.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Orange County Advanced Power Station

In September 2021, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station, a new 1,215 MW combined cycle combustion turbine facility to be located in Bridge City, Texas at an initially-estimated expected total cost of $1.2 billion inclusive of the estimated costs of the generation facilities, transmission upgrades, contingency, an allowance for funds used during construction, and necessary regulatory expenses, among others. The project includes combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future. In December 2021 the PUCT referred the proceeding to the State Office of Administrative Hearings. In March 2022 certain intervenors filed testimony opposing the hydrogen co-firing component of the proposed project and others filed testimony opposing the project outright. Also in March 2022 the PUCT staff filed testimony opposing the hydrogen co-firing component of the proposed project, but otherwise taking no specific position on the merits of the project. The PUCT staff also proposed that the PUCT establish a maximum amount that Entergy Texas may recover in rates attributable to the project. In April 2022, Entergy Texas filed rebuttal testimony addressing and rebutting these various arguments. The hearing on the merits was held in June 2022, and post-hearing briefs were submitted in July 2022. In September 2022 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application for certification of Orange County Advanced Power Station subject to certain conditions, including a cap on cost recovery at $1.37 billion, the exclusion of investment associated with co-firing hydrogen, weatherization requirements, and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate. In October 2022 the parties in the proceeding filed exceptions and replies to exceptions to the proposal for decision. Also in October 2022, Entergy Texas filed with the PUCT information regarding a new fixed pricing option for an estimated project cost of approximately $1.55 billion associated with Entergy Texas’s issuance of limited notice to proceed by mid-November 2022. In November 2022 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Orange County Advanced Power Station without the investment associated with hydrogen co-firing capability, without a cap on cost recovery, and subject to certain conditions, including weatherization requirements and customer receipt of any contractual benefits associated with the facility’s guaranteed heat rate.

In December 2022, Texas Industrial Energy Consumers and Sierra Club filed motions for rehearing of the PUCT’s final order alleging the PUCT erred in granting the certification of the Orange County Advanced Power Station, in not imposing a cost cap, in including certain findings related to the reasonableness of Entergy Texas’s request for proposals from which the Orange County Advanced Power Station was selected, and in other regards. Also in December 2022, Entergy Texas filed a response to the motions for rehearing refuting the points raised therein. In January 2023 the PUCT issued letters noting that it voted to consider Texas Industrial Energy Consumers’ motion for rehearing at its upcoming January 2023 open meeting and voted not to consider Sierra Club’s motion for rehearing at an open meeting. At the January 2023 open meeting, the PUCT voted to grant Texas Industrial Energy Consumers’ motion for rehearing for the limited purpose of issuing an order on rehearing that excludes three findings related to Entergy Texas’s request for proposals. The order on rehearing does not change the PUCT’s certification of the Orange County Advanced Power Station or the conditions placed thereon in the PUCT’s November 2022 final order. Construction is in progress, and subject to receipt of required permits, the facility is expected to be in service by mid-2026.

Legend Power Station and Lone Star Power Station

In June 2024, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the Legend Power Station, a 754 MW combined cycle combustion turbine facility, which will be enabled for future carbon capture and storage and for hydrogen co-firing optionality, to be located in Jefferson County, Texas, and the Lone Star Power Station, a 453 MW simple cycle combustion turbine facility, which will be enabled with hydrogen co-firing optionality, to be located in Liberty County, Texas. In its application, Entergy Texas noted that the Legend Power Station was

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

expected to cost an estimated $1.46 billion and the Lone Star Power Station was expected to cost an estimated $735.3 million, in each case inclusive of the estimated costs of the generation facilities, interconnection costs, transmission network upgrades, and an allowance for funds used during construction. In July 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings and, also in July 2024, the ALJ with the State Office of Administrative Hearings adopted a procedural schedule, with a hearing on the merits scheduled to begin in October 2024. In September 2024, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a motion to extend the procedural schedule in this proceeding in order to address certain developments relating to the cost and scope of the Legend Power Station and the Lone Star Power Station. In December 2024, Entergy Texas filed supplemental testimony and exhibits addressing the cost and scope developments associated with the Legend Power Station and the Lone Star Power Station in further support of its application. The cost and scope developments include cost estimate increases of $139 million for Legend Power Station and $63.7 million for Lone Star Power Station and the consideration of an alternate site for Lone Star Power Station, which would reduce the estimated cost increase of the Lone Star Power Station to $36.2 million. In March 2025, Entergy Texas filed testimony explaining that Entergy Texas planned to move forward with building the Lone Star Power Station on a more cost-effective alternative site in San Jacinto County, Texas. A hearing on the merits was held in April 2025. Also in April 2025, Entergy Texas, intervenors, and the PUCT staff filed initial briefs. In its initial brief, the PUCT staff recommended denial of Entergy Texas’s application or, in the alternative, approval subject to conditions that include a prudence review by an external consultant if actual project costs exceed estimated costs by more than 10%, transmission cost reporting, and weatherization of both the Legend Power Station and the Lone Star Power Station. Certain intervenors requested that the PUCT impose various conditions upon the approval of the resources, including, among others, cost recovery limitations, a direction that Entergy Texas initiate a competitive tariff proceeding to facilitate industrial sleeving, a requirement for additional regulatory approvals related to hydrogen or carbon capture and storage implementation, limits on the recovery of supplemental filing costs, and calculation of AFUDC based on an adjusted weighted average cost of capital. Reply briefs were filed in May 2025. In June 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision, in which they recommended rejection of Entergy Texas’s application to construct the Legend Power Station and the Lone Star Power Station based upon their finding that Entergy Texas did not demonstrate the resources to be cost-effective alternatives to address the uncontested need for additional generation. In the alternative, the ALJs recommended that if the PUCT approves the resources, that conditions be imposed, including a deferral of the finding that the resources were prudently selected until Entergy Texas’s next rate case, a prudence review by an external consultant if actual project costs exceed estimated costs by more than 10%, weatherization requirements, and a requirement that Entergy Texas obtain additional regulatory approvals prior to implementing hydrogen co-firing or carbon capture and storage. The ALJs’ proposal for decision was an interim step in the certification process and was not binding upon the PUCT. Entergy Texas filed exceptions in July 2025. In September 2025 the PUCT issued a decision granting the application, subject to conditions that include a cost cap at Entergy Texas’s previously-filed modified estimated costs of $1.6 billion for the Legend Power Station and $799 million for the Lone Star Power Station, weatherization requirements, environmental compliance requirements, and a requirement to request additional authorization prior to implementing hydrogen co-firing or carbon capture and storage. In October 2025 an intervenor filed a motion for rehearing requesting that the PUCT modify the Lone Star Power Station cost cap to reflect the estimated project costs associated with a new project site, clarify that the cost cap is inclusive of transmission upgrades, and reconsider the intervenor’s prior proposal for a “soft cost cap” below the estimated project costs, and that Entergy Texas be directed to initiate a competitive tariff proceeding to facilitate industrial sleeving of purchased power. Entergy Texas filed a response to the motion for rehearing in October 2025. In December 2025 the PUCT issued an order on rehearing modifying the Lone Star Power Station cost cap to $771.5 million to reflect the estimated project costs associated with a new project site and clarifying that the cost cap is inclusive of transmission upgrades, but denying the other relief requested in the motion for rehearing. See Note 8 to the financial statements for discussion of the build-to-suit lease arrangement for the Legend Power Station. Construction is underway, and subject to receipt of required permits and other conditions, both facilities are expected to be in service by mid-2028.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Segno Solar and Votaw Solar

Southeast Texas Area Reliability Project (SETEX)

In February 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities. The transmission line is expected to be approximately 131 to 160 miles in length and the estimated cost of the project ranges from $1.3 billion to $1.5 billion, depending upon the route ultimately approved by the PUCT. Also in February 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings. A hearing on the merits was held in May 2025. In July 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct SETEX and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $1.4 billion. In October 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line and associated stations and 138/230 kV facilities, and selecting the final route for the project, which has an estimated cost of $1.36 billion. In November 2025, multiple parties filed motions for rehearing primarily challenging the routing of the transmission line. In December 2025 the PUCT issued an order on rehearing reaffirming and providing additional support for its initial decision. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2029.

Legend to Sandling 230kV Transmission Line

In April 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 230 kV transmission line. The transmission line is expected to be approximately 9 to 10 miles in length and the estimated cost of the project ranges from $87.4 million to $88.6 million, depending on the route ultimately approved by the PUCT. Also in April 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2025, Entergy Texas filed an unopposed settlement agreement resolving all issues in the proceeding and a joint motion, which the ALJ with the State Office of Administrative Hearings granted, on behalf of the parties to the proceeding to cancel the remaining procedural schedule, to admit evidence, and to remand the proceeding to the PUCT to consider the unopposed settlement agreement. In September 2025 the PUCT issued a notice of approval for the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 230 kV transmission line, with a selected route at an estimated cost of $87.6 million. Subject to receipt of required permits and other conditions, the facility is expected to be in service by second quarter 2027.

Cypress to Legend 500 kV Transmission Line

In May 2025, Entergy Texas filed an application seeking PUCT approval to amend Entergy Texas’s certificate of convenience and necessity to construct, own, and operate a new single-circuit 500 kV transmission line. The transmission line is expected to be approximately 40 to 49 miles in length and the estimated cost of the project ranges from $392.7 million to $436.2 million, depending on the route ultimately approved by the PUCT. In June 2025 the PUCT referred the proceeding to the State Office of Administrative Hearings and a hearing on the

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

merits was held in August 2025. In October 2025 the ALJs with the State Office of Administrative Hearings issued a proposal for decision recommending the PUCT approve Entergy Texas’s application to construct the transmission line and recommending the PUCT’s approval include selection of a specific route with an estimated cost of $398.7 million. In December 2025 the PUCT issued a final order approving the requested amendment to Entergy Texas’s certificate of convenience and necessity to construct, own, and operate the new single-circuit 500 kV transmission line, and selecting the final route previously recommended. In February 2026, landowners not party to the PUCT proceeding filed in the 345th District Court of Travis County, Texas a petition for declaratory relief and temporary and permanent injunction against the PUCT’s final order. The petition, which names the PUCT, its commissioners, and Entergy Texas as defendants, challenges Entergy Texas’s notice, the application of the PUCT’s notice rule, and the PUCT order’s approval of a route the petitioner’s assert was not adequately noticed. Entergy Texas expects to file an answer disputing all aspects of the petition by the applicable deadline. Subject to receipt of required permits and other conditions, the facility is expected to be in service by the end of 2028.

Resilience and Grid Hardening

In June 2024, Entergy Texas filed an application with the PUCT requesting approval of Phase I of its Texas Future Ready Resiliency Plan, a set of measures to begin accelerating the resiliency of Entergy Texas’s transmission and distribution system. Phase I is comprised of projects totaling approximately $335.1 million, including approximately $137 million of projects to be funded by Entergy Texas and approximately $198 million of projects contingent upon Entergy Texas’s receipt of grant funds in that amount from the Texas Energy Fund. The projects in Phase I include distribution and transmission hardening and modernization projects and targeted vegetation management projects to mitigate the risk of wildfire. These projects are expected to be implemented within approximately three years of PUCT approval. In January 2025 the PUCT unanimously approved Phase I of Entergy Texas’s Texas Future Ready Resiliency Plan, including the approximately $137 million of projects to be funded by Entergy Texas and application of performance metrics consistent with the unopposed settlement. The PUCT clarified that, while not part of Entergy Texas’s Phase I plan, Entergy Texas is permitted to pursue the remaining $198 million of identified projects and Texas Energy Fund grant funding for those projects. In February 2025 the PUCT issued an order adopting a new rule establishing the procedures for application to the grant fund. In July 2025, Entergy Texas submitted an application for approximately $200 million in grant funding from the Texas Energy Fund to implement the resilience projects originally included in its Texas Future Ready Resiliency Plan. In October 2025 the PUCT voted to approve the approximately $200 million grant request in full. The portion of the projects funded by Entergy Texas will be eligible for recovery through Entergy Texas’s transmission or distribution cost recovery factor riders, as applicable.

Sources of Capital

Entergy Texas’s sources to meet its capital requirements include:

internally generated funds;
cash on hand;
the Entergy system money pool;
debt or preferred stock issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
capital contributions; and
bank financing under new or existing facilities.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, Entergy Texas expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

Entergy Texas’s receivables from the money pool were as follows as of December 31 for each of the following years.


2025	2024	2023	2022
(In Thousands)
$22,467	$18,504	$317,882	$99,468

See Note 4 to the financial statements for a description of the money pool.

Entergy Texas has a credit facility in the amount of $300 million scheduled to expire in June 2030. The credit facility includes fronting commitments for the issuance of letters of credit against $25 million of the borrowing capacity of the facility. As of December 31, 2025, there were no cash borrowings and $1.1 million in letters of credit outstanding under the credit facility. In addition, Entergy Texas is a party to two uncommitted letter of credit facilities as a means to post collateral to support its obligations to MISO. As of December 31, 2025, $59.6 million in letters of credit were outstanding under one of Entergy Texas’s uncommitted letter of credit facilities. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Texas obtained authorizations from the FERC through January 2027 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.

Build-to-Suit Lease Arrangement for the Legend Power Station

In December 2025, Entergy Texas entered into a build-to-suit lease arrangement for the Legend Power Station as the lessee with a consortium of investors (the Investors). Under the terms of the arrangement, the Investors purchased the in-process Legend Power Station construction project from Entergy Texas at a cost of $359 million and will spend up to $1.45 billion (including the initial purchase price) to construct the Legend Power Station project as designed by Entergy Texas. Entergy Texas is engaged to serve as the construction agent for the Legend Power Station project. The Investors, however, control the asset during construction. If Entergy Texas defaults in its role as construction agent, the Investors have various options available to remedy the default, including by accelerating the lease balance payable by Entergy Texas, causing a sale of the Legend Power Station project to a third party, or certain other options. If there are certain changes to the terms of the PUCT approval of the Legend Power Station project or certain other circumstances outside of Entergy Texas’s control, then either the Investors or Entergy Texas could exercise the right to terminate the arrangement, in which case Entergy Texas would be required to purchase the in-process Legend Power Station project from the Investors at an amount equal to their costs incurred to date, including carrying costs. Since Entergy Texas does not control the in-process construction project, it will not recognize the asset (i.e., construction work in progress) or an associated liability during construction.

Upon the Legend Power Station’s readiness for first synchronization to the grid, expected in early 2028, a triple-net lease will commence under which Entergy Texas will have control of the Legend Power Station and receive all output from the plant. The initial term of the lease will end seven years from the closing of the arrangement, or approximately five years after the Legend Power Station’s expected readiness for first synchronization to the grid. The lease cost will be equal to the Secured Overnight Financing Rate plus a margin which is based on the credit rating of Entergy Texas, multiplied by the total costs (including carrying costs) incurred by the Investors as of the commencement of the lease. Entergy Texas will have the option to purchase the Legend Power Station at any time during the lease term at a price equal to the total cost of the plant to the Investors, plus

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

any fees and carrying charges owed to the Investors. If the purchase price option is exercised within two years of commencement of the triple-net lease, Entergy Texas must enter into a secured note payable to the Investors for the amount of the purchase price. The note payable would be due at the end of the initial lease term, but may be prepaid at any time beginning two years after the commencement date of the lease. The note will be secured by the Legend Power Station and related equipment and collateral.

At the end of the initial lease term, Entergy Texas must exercise one of the following options: 1) renew the lease for an additional five year term, subject to unanimous consent of the Investors, 2) purchase the plant at a price equal to the total cost of the plant to Investors, plus any fees and carrying charges owed to the Investors, or 3) sell the plant on behalf of the Investors. If Entergy Texas chooses the third option, then it will owe or be owed any difference between the total cost of the plant to Investors and the sale price.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated, and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the PUCT, is primarily responsible for approval of the rates charged to customers.

Filings with the PUCT and Texas Cities

Retail Rates

2022 Base Rate Case

In July 2022, Entergy Texas filed a base rate case with the PUCT seeking a net increase in base rates of approximately $131.4 million. The base rate case was based on a 12-month test year ending December 31, 2021. Key drivers of the requested increase were changes in depreciation rates as the result of a depreciation study and an increase in the return on equity. In addition, Entergy Texas included capital additions placed into service for the period of January 1, 2018 through December 31, 2021, including those additions reflected in the then-effective distribution and transmission cost recovery factor riders and the generation cost recovery rider, all of which were reset to zero in June 2023 as a result of this proceeding. In July 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In October 2022 intervenors filed direct testimony challenging and supporting various aspects of Entergy Texas’s rate case application. The key issues addressed included the appropriate return on equity, generation plant deactivations, depreciation rates, and proposed tariffs related to electric vehicles. In November 2022 the PUCT staff filed direct testimony addressing a similar set of issues and recommending a reduction of $50.7 million to Entergy Texas’s overall cost of service associated with the requested net increase in base rates of approximately $131.4 million. Entergy Texas filed rebuttal testimony in November 2022.

In May 2023, Entergy Texas filed on behalf of the parties an unopposed settlement resolving all issues in the proceeding, except for issues related to electric vehicle charging infrastructure which were eventually severed to a separate proceeding and resolved in October 2024, and Entergy Texas filed an agreed motion for interim rates, subject to refund or surcharge to the extent that the interim rates differ from the final approved rates. The unopposed settlement reflected a net base rate increase to be effective and relate back to December 2022 of $54 million, exclusive of, and incremental to, the costs being realigned from the distribution and transmission cost recovery factor riders and the generation cost recovery rider and $4.8 million of rate case expenses to be recovered through a rider over a period of 36 months. The net base rate increase of $54 million includes updated depreciation rates and a total annual revenue requirement of $14.5 million for the accrual of a self-insured storm reserve and the recovery of the regulatory assets for the pension and postretirement benefits expense deferral, costs associated with the COVID-19 pandemic, and retired non-advanced metering system electric meters. In May 2023 the ALJ with the State Office of Administrative Hearings granted the motion for interim rates, which became effective in June 2023. Additionally, the ALJ remanded the proceeding to the PUCT to consider the settlement. In August 2023 the PUCT

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

issued an order approving the unopposed settlement. Concurrently, Entergy Texas recorded the reversal of $21.9 million of regulatory liabilities to reflect the recognition of certain receipts by Entergy Texas under affiliated PPAs that have been resolved.

Following the PUCT’s approval of the unopposed settlement in August 2023, Entergy Texas recorded a regulatory liability of $10.3 million, which reflected the net effects of higher depreciation and amortizations for the relate back period, partially offset by the relate back of base rate revenues that would have been collected had the approved rates been in effect for the period from December 2022 through June 2023, the date the new base rates were implemented on an interim basis. In October 2023, Entergy Texas filed a relate back surcharge rider to collect over six months beginning in January 2024 an additional approximately $24.6 million, which was the revenue requirement associated with the relate back of rates from December 2022 through June 2023, including carrying costs, as authorized by the PUCT’s August 2023 order. In November 2023, Entergy Texas filed an amended relate back surcharge rider to collect approximately $24.1 million based on a revised carrying cost rate. The amended relate back surcharge rider was approved by the PUCT in December 2023. The higher depreciation and amortizations for the relate back period were also recognized over the six months beginning in January 2024, resulting in no effect on net income from the collection of the relate back surcharge rider.

Distribution Cost Recovery Factor (DCRF) Rider

In June 2024, Entergy Texas filed with the PUCT a request to set a new DCRF rider. The new rider was designed to collect from Entergy Texas’s retail customers approximately $40.3 million annually based on its capital invested in distribution between January 1, 2022 and March 31, 2024. In September 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective with the first billing cycle in October 2024.

In September 2024, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $48.9 million annually, or $8.6 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between April 1, 2024 and June 30, 2024. In December 2024, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $48.5 million. The amended request represented an incremental increase of $8.2 million in annual revenues beyond Entergy Texas’s then-effective DCRF rider. Also in December 2024 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 20, 2024.

In April 2025, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $77.8 million annually, or $29.3 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between July 1, 2024 and December 31, 2024, including distribution-related restoration costs associated with Hurricane Beryl. In June 2025 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective on June 25, 2025.

In September 2025, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $94.7 million annually, or $16.9 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between January 1, 2025 and June 30, 2025. In November 2025, Entergy Texas filed an errata to revise its DCRF application for minor corrections, which decreased the requested annual revenue requirement to $92.1 million. The amended request represented an incremental increase of $14.3 million in annual revenues beyond Entergy Texas’s then-effective DCRF filing. In December 2025 the PUCT approved the DCRF rider, consistent with Entergy Texas’s filed errata, and rates became effective on December 15, 2025.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Transmission Cost Recovery Factor (TCRF) Rider

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

In October 2024, Entergy Texas filed with the PUCT a request to amend its TCRF rider, which was previously reset to zero in June 2023 as a result of the 2022 base rate case. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $9.7 million annually based on its capital invested in transmission between January 1, 2022 and June 30, 2024 and changes in other transmission charges. In April 2025 the PUCT approved the TCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective for usage on and after April 7, 2025.

In October 2025, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $30.3 million annually, or $20.6 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2024 and June 30, 2025 and changes in other transmission charges. In January 2026 the PUCT staff filed a recommendation that the PUCT approve Entergy Texas’s as-filed application.

Generation Cost Recovery Rider

In December 2020, Entergy Texas also filed an application to amend its generation cost recovery rider to reflect its acquisition of the Hardin County Peaking Facility, which closed in June 2021. Because the facility was to be acquired in the future, the initial generation cost recovery rider rates proposed in the application represented no change from the generation cost recovery rider rates established in Entergy Texas’s previous generation cost recovery rider proceeding. In July 2021 the PUCT issued an order approving the application. In August 2021, Entergy Texas filed an update application to recover its actual investment in the acquisition of the Hardin County Peaking Facility, and in January 2022, Entergy Texas filed an update to its application to align the requested revenue requirement with the terms of the generation cost recovery rider settlement approved by the PUCT in January 2022. In April 2022, Entergy Texas filed on behalf of the parties a unanimous settlement agreement that would adjust its generation cost recovery rider to recover an annual revenue requirement of approximately $92.8 million, which was $4.5 million in incremental annual revenue above the revenue requirement approved in January 2022 described above and related to Entergy Texas’s investment in the Montgomery County Power Station. The PUCT approved the settlement agreement and rates became effective in August 2022. In September 2022, Entergy Texas filed a relate-back rider designed to collect over three months an additional approximately $5.7 million, which is the revenue requirement, plus carrying costs, associated with Entergy Texas’s acquisition of Hardin County Peaking Facility from June 2021 through August 2022 when the updated revenue requirement took effect. In April 2023 the PUCT approved Entergy Texas’s as-filed request with rates effective over three months beginning in May 2023.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Fuel and purchased power cost recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. 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 2023 the Texas legislature modified the Texas Utilities Code with regard to how material over- and under-recovered fuel balances are to be addressed and directed that fuel reconciliations must be filed at least once every two years. In July 2025 the PUCT initiated a rulemaking to effectuate the new legislation. In December 2025 the PUCT adopted amendments to its fuel rules that maintain a periodic revision to utility fuel factors coupled with accelerated processing of surcharges and refunds to address material over- and under-recovered amounts.

In September 2022, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2019 through March 2022. During the reconciliation period, Entergy Texas incurred approximately $1.7 billion in eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. As of the end of the reconciliation period, Entergy Texas’s cumulative under-recovery balance was approximately $103.1 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning April 2022, pending future surcharges or refunds as approved by the PUCT. In November 2022 the PUCT referred the proceeding to the State Office of Administrative Hearings. In July 2023, Entergy Texas filed an unopposed settlement, supporting testimony, and an agreed motion to admit evidence and remand the proceeding to the PUCT. Pursuant to the unopposed settlement, Entergy Texas would receive no disallowance of fuel costs incurred over the three-year reconciliation period and retain $9.3 million in margins from off-system sales made during the reconciliation period, resulting in a cumulative under-recovery balance of approximately $99.7 million, including interest, as of the end of the reconciliation period. In July 2023 the ALJ with the State Office of Administrative Hearings granted the motion to admit evidence and remanded the proceeding to the PUCT for consideration of the unopposed settlement. The PUCT approved the settlement in September 2023.

In September 2024, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2022 through March 2024. During the reconciliation period, Entergy Texas incurred approximately $1.6 billion in eligible fuel and purchased power expenses to generate and purchase electricity to serve its customers, net of certain revenues credited to such expenses and other adjustments. Entergy Texas’s cumulative under-recovery balance for the reconciliation period was approximately $30 million, including interest, which Entergy Texas requested authority to carry over as part of the cumulative fuel balance for the subsequent reconciliation period beginning April 2024. In March 2025, Texas Industrial Energy Consumers, an intervenor, filed testimony regarding the recovery of capacity costs for a certain power purchase agreement, arguing the capacity costs should be imputed and treated as non-reconcilable fuel expense, recovered in Entergy Texas’s base rates. In April 2025 the PUCT staff filed testimony and later in April 2025, Entergy Texas filed rebuttal testimony. In August 2025, Entergy Texas filed an unopposed settlement agreement that results in no disallowance and establishes a regulatory asset for the future recovery of imputed capacity costs and associated carrying costs related to a certain purchased power agreement, with recovery effective retroactive to June 1, 2024. In October 2025 the PUCT approved the unopposed settlement agreement.

In December 2024, Entergy Texas filed an application with the PUCT to implement an interim fuel refund of $45.5 million, including interest. Entergy Texas proposed that the interim fuel refund be implemented over a three-month period beginning with the first billing cycle in February 2025 for residential and other small customers and through a one-time credit, or surcharge depending on historical usage for the respective customer, for certain transmission voltage level and seasonal agricultural customers in February 2025. Also in December 2024 the PUCT referred the proceeding to the State Office of Administrative Hearings. In January 2025 the ALJ with the State Office of Administrative Hearings issued an order approving the interim fuel refund consistent with Entergy

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Texas’s application and, because no hearing was requested in the proceeding, dismissing the case from the State Office of Administrative Hearings and the PUCT.

Industrial and Commercial Customers

Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. Entergy Texas responds by working with industrial and commercial customers to negotiate electric service contracts, under existing rate schedules, with competitive rates that match specific customer needs and load profiles. Additionally, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand from both new and existing customers.

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 Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Texas’s financial statements in conformity with 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 Texas’s financial position, results of operations, or cash flows.

Utility Regulatory Accounting

Taxation and Uncertain Tax Positions

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Qualified Pension and Other Postretirement Benefits

Entergy Texas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are 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 2026 Qualified Pension Cost	Impact on 2025 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$141	$4,530
Rate of return on plan assets	(0.25%)	$571	$—
Rate of increase in compensation	0.25%	$198	$893

The following chart reflects the sensitivity of postretirement benefits cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).


Actuarial Assumption	Change in Assumption	Impact on 2026 Postretirement Benefits Cost	Impact on 2025 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$31	$1,003
Health care cost trend	0.25%	$44	$592

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Employer Contributions

Total qualified pension cost for Entergy Texas in 2025 was $2.7 million, including $617 thousand in settlement costs. Entergy Texas anticipates 2026 qualified pension cost to be $1.5 million. Entergy Texas contributed $7.7 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $5.9 million, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026.

Total postretirement health care and life insurance benefit income for Entergy Texas in 2025 was $10.6 million. Entergy Texas expects 2026 postretirement health care and life insurance benefit income to approximate $9.6 million. In 2025, Entergy Texas’ contributions to its other postretirement plans, specifically contributions to the external trusts plus claims payments, were offset by trust claims reimbursements, resulting in a net reimbursement of $171 thousand. Entergy Texas estimates that 2026 contributions will be approximately $149 thousand.

Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Other Contingencies

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 shareholders and Board of Directors of

Entergy Texas, Inc. and Subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, cash flows, and changes in equity (pages 449 through 454 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for 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 Texas, Inc. and Subsidiaries — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to rate regulation by the Public Utility Commission of Texas (the “PUCT”), which has jurisdiction with respect to the rates of electric companies in Texas, and to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the PUCT and the FERC set the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT and the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the 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 the likelihood of refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by the PUCT 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 PUCT 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 PUCT 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 PUCT’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 PUCT and the FERC and orders issued, and considered the filings with the PUCT and the FERC by intervenors that may impact the Company’s future rates, for any evidence that might contradict management’s assertions*.*
We obtained an analysis from management and support from internal and external legal counsel, as appropriate, regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or refund 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.

Entergy Texas Build-to-Suit Lease Arrangement for the Legend Power Station—Entergy Texas, Inc. and Subsidiaries — Refer to Note 8 to the financial statements

Critical Audit Matter Description

In December 2025, the Company entered into a build-to-suit lease arrangement for the Legend Power Station (the “Facility”) as the lessee with a consortium of investors (“the Investors”). Under the terms of the arrangement, the Investors purchased the in-process Facility from the Company at cost of $359 million and will spend up to $1.45 billion (including the initial purchase price) to construct the Facility as designed by the Company. The Company is engaged to serve as the construction agent for the Facility. The Investors, however, control the Facility during

construction. If the Company defaults in its role as construction agent, the Investors have various options available to remedy the default, including by accelerating the lease balance payable by the Company, causing a sale of the Facility to a third party, or certain other options. If there are certain changes to the terms of the PUCT approval of the Facility or certain other circumstances outside of the Company’s control, then either the Investors or the Company could exercise the right to terminate the arrangement, in which case the Company would be required to purchase the in-process Facility from the Investors at an amount equal to their costs incurred to date, including carrying costs. Since the Company does not control the in-process Facility, it will not recognize the Facility (i.e., construction work in progress) or an associated liability during construction.

Upon the Facility’s readiness for first synchronization to the grid, expected in early 2028, a triple-net lease will commence under which the Company will have control of the Facility and receive all output from the plant.

We identified management’s conclusion that the Company does not control the Facility being constructed before the commencement of the lease (i.e., during the construction period) and thus is not the deemed accounting owner of the Facility during the construction period 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 lease transactions.

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures related to the build-to-suit lease arrangement for the Facility included the following, among others:

We tested the effectiveness of management’s controls over the evaluation of the accounting impact of this build-to-suit lease arrangement, including the conclusion that the Company does not control the Facility being constructed before the commencement of the lease.
We evaluated the Company’s disclosures related to the impacts of the build-to-suit lease arrangement.
We read relevant transaction documents between the Company and the Investors as well as regulatory orders issued by the PUCT for the Company and evaluated the external information to compare to management’s conclusions.
We obtained an analysis from management to assess management’s assertion that the Company does not control the Facility being constructed before the commencement date of the lease.
With the assistance of professionals in our firm having expertise and experience in addressing the accounting for build-to-suit lease arrangements, we evaluated the Company’s analysis, including the conclusion that the Company does not control the Facility being constructed before the commencement date of the lease.
We obtained representation from management regarding the conclusion that the Company does not control the Facility being constructed before the commencement date of the lease.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 19, 2026

We have served as the Company’s auditor since 2001.


ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING REVENUES
Electric	$2,127,584	$2,050,150	$2,028,586

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	351,554	482,486	403,111
Purchased power	497,113	373,036	468,511
Other operation and maintenance	359,812	340,956	323,797
Taxes other than income taxes	120,919	101,993	117,852
Depreciation and amortization	325,185	338,890	278,311
Other regulatory charges (credits) - net	13,732	(13,884)	7,324
TOTAL	1,668,315	1,623,477	1,598,906

OPERATING INCOME	459,269	426,673	429,680

OTHER INCOME
Allowance for equity funds used during construction	81,771	47,833	28,193
Interest and investment income	5,964	15,107	11,116
Miscellaneous - net	(8,824)	(11,113)	(10,411)
TOTAL	78,911	51,827	28,898

INTEREST EXPENSE
Interest expense	173,565	137,820	114,978
Allowance for borrowed funds used during construction	(34,822)	(18,626)	(10,545)
TOTAL	138,743	119,194	104,433

INCOME BEFORE INCOME TAXES	399,437	359,306	354,145

Income taxes	65,366	65,684	62,872

NET INCOME	334,071	293,622	291,273

Preferred dividend requirements	2,072	2,072	2,072

EARNINGS APPLICABLE TO COMMON STOCK	$331,999	$291,550	$289,201

See Notes to Financial Statements.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING ACTIVITIES
Net income	$334,071	$293,622	$291,273
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization	325,185	338,890	278,311
Deferred income taxes, tax credits, and non-current taxes accrued	37,714	35,631	53,507
Changes in assets and liabilities:
Receivables	(43,441)	(13,201)	24,249
Fuel inventory	15,137	4,877	(24,097)
Accounts payable	10,245	41,216	(22,046)
Taxes accrued	10,706	(2,413)	(14,146)
Interest accrued	3,204	7,418	7,357
Deferred fuel costs	(47,918)	198,290	119,096
Other working capital accounts	(50,423)	(38,672)	(36,097)
Provisions for estimated losses	3,573	505	1,887
Other regulatory assets	38,902	46,898	(17,924)
Other regulatory liabilities	84,253	(45,301)	(20,122)

Pension and other postretirement funded status	(29,430)	(29,062)	(36,131)
Other assets and liabilities	(63,865)	(15,049)	36,574
Net cash flow provided by operating activities	627,913	823,649	641,691
INVESTING ACTIVITIES
Construction expenditures	(1,720,604)	(1,287,518)	(946,543)
Allowance for equity funds used during construction	81,771	47,833	28,193
Proceeds from sale of assets	400,266	2,396	11,000


Changes in money pool receivable - net	(3,963)	299,378	(218,414)
Changes in securitization account	1,223	2,493	5,684
Decrease (increase) in other investments	—	7,000	(5,868)
Net cash flow used in investing activities	(1,241,307)	(928,418)	(1,125,948)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	493,515	343,124	344,895
Retirement of long-term debt	(18,847)	(18,334)	(17,835)
Capital contributions from parent	225,000	—	150,000

Dividends paid:
Common stock	—	(69,000)	—
Preferred stock	(2,072)	(2,072)	(2,072)
Other	5,909	14,062	27,758
Net cash flow provided by financing activities	703,505	267,780	502,746
Net increase in cash and cash equivalents	90,111	163,011	18,489
Cash and cash equivalents at beginning of period	184,997	21,986	3,497
Cash and cash equivalents at end of period	$275,108	$184,997	$21,986
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized	$160,072	$127,342	$104,766
Income taxes - net	$23,517	$34,077	$28,969
Noncash investing activities:
Accrued construction expenditures	$102,988	$279,480	$257,467

See Notes to Financial Statements.


ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2025	2024
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$200	$291
Temporary cash investments	274,908	184,706
Total cash and cash equivalents	275,108	184,997
Securitization recovery trust account	1,480	2,703
Accounts receivable:
Customer	107,287	84,842
Allowance for doubtful accounts	(8,598)	(1,304)
Associated companies	28,747	26,564
Other	67,400	43,773
Accrued unbilled revenues	80,503	74,060
Total accounts receivable	275,339	227,935

Fuel inventory - at average cost	30,833	45,970
Materials and supplies	190,322	157,241
Prepayments and other	49,161	34,803
TOTAL	822,243	653,649

OTHER PROPERTY AND INVESTMENTS
Investments in affiliates - at equity	56	107
Other	15,607	15,878
TOTAL	15,663	15,985

UTILITY PLANT
Electric	9,491,159	8,628,625
Construction work in progress	1,761,028	1,513,170
TOTAL UTILITY PLANT	11,252,187	10,141,795
Less - accumulated depreciation and amortization	2,764,308	2,548,961
UTILITY PLANT - NET	8,487,879	7,592,834

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets (includes securitization property of $216,107 as of December 31, 2025 and $234,112 as of December 31, 2024)	510,806	549,708
Other	191,555	157,904
TOTAL	702,361	707,612

TOTAL ASSETS	$10,028,146	$8,970,080

See Notes to Financial Statements.


ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2025	2024
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$130,000	$—
Accounts payable:
Associated companies	73,178	65,335
Other	518,613	361,404
Customer deposits	42,109	40,782
Taxes accrued	87,180	76,474
Interest accrued	41,907	38,703
Deferred fuel costs	11,353	59,271
Other	16,801	20,836
TOTAL	921,141	662,805

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	947,067	868,849
Accumulated deferred investment tax credits	6,467	7,215
Regulatory liability for income taxes - net	57,755	93,766
Other regulatory liabilities	138,969	18,705
Asset retirement cost liabilities	15,097	17,688
Accumulated provisions	13,558	9,985
Long-term debt (includes securitization bonds of $221,139 as of December 31, 2025 and $239,622 as of December 31, 2024)	3,900,188	3,552,443
Other	129,693	397,412
TOTAL	5,208,794	4,966,063

Commitments and Contingencies

EQUITY
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2025 and 2024	49,452	49,452
Paid-in capital	1,425,125	1,200,125
Retained earnings	2,384,884	2,052,885
Total common shareholder's equity	3,859,461	3,302,462
Preferred stock without sinking fund	38,750	38,750
TOTAL	3,898,211	3,341,212

TOTAL LIABILITIES AND EQUITY	$10,028,146	$8,970,080

See Notes to Financial Statements.


ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2025, 2024, and 2023

		Common Equity
	Preferred Stock	Common Stock	Paid-in Capital	Retained Earnings	Total
		(In Thousands)

Balance at December 31, 2022	$38,750	$49,452	$1,050,125	$1,541,134	$2,679,461
Net income	—	—	—	291,273	291,273
Capital contribution from parent	—	—	150,000	—	150,000

Preferred stock dividends	—	—	—	(2,072)	(2,072)
Balance at December 31, 2023	$38,750	$49,452	$1,200,125	$1,830,335	$3,118,662
Net income	—	—	—	293,622	293,622

Common stock dividends	—	—	—	(69,000)	(69,000)
Preferred stock dividends	—	—	—	(2,072)	(2,072)
Balance at December 31, 2024	$38,750	$49,452	$1,200,125	$2,052,885	$3,341,212
Net income	—	—	—	334,071	334,071
Capital contribution from parent	—	—	225,000	—	225,000

Preferred stock dividends	—	—	—	(2,072)	(2,072)
Balance at December 31, 2025	$38,750	$49,452	$1,425,125	$2,384,884	$3,898,211

See Notes to Financial Statements.

SYSTEM ENERGY RESOURCES, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

System Energy’s principal asset consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only three customers, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans. System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. See Note 8 to the financial statements for additional information regarding the amended Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues. As discussed in “Complaints Against System Energy” in Note 2 to the financial statements, System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC.

Results of Operations

2025 Compared to 2024

Net Income

Net income decreased $15.4 million primarily due to a lower rate of return on rate base, including the effects of the lower authorized rate of return on equity and capital structure limitations reflected in monthly bills issued to Entergy Louisiana effective with the September 2024 service month per the settlement agreement with the LPSC and the lower authorized rate of return on equity and capital structure limitations reflected in monthly bills issued to Entergy New Orleans effective with the June 2024 service month per the settlement agreement with the City Council. See Note 2 to the financial statements for discussion of the settlements with the City Council and the LPSC.

Income Taxes

The effective income tax rates were 18.2% for 2025 and 22.2% for 2024. 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.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Results of Operations” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of results of operations for 2024 compared to 2023.

Income Tax Legislation and Regulation

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2025, 2024, and 2023 were as follows:


	2025	2024	2023
	(In Thousands)
Cash and cash equivalents at beginning of period	$28,908	$60	$2,940

Net cash provided by (used in):
Operating activities	251,740	31,505	273,572
Investing activities	(191,229)	(317,935)	(75,806)
Financing activities	(89,363)	315,278	(200,646)
Net increase (decrease) in cash and cash equivalents	(28,852)	28,848	(2,880)

Cash and cash equivalents at end of period	$56	$28,908	$60

2025 Compared to 2024

Operating Activities

Net cash flow provided by operating activities increased $220.2 million in 2025 primarily due to:

the receipt of $133.8 million related to the transfer of the 2024 nuclear production tax credits to third parties in 2025. See Note 3 to the financial statements for discussion of the nuclear production tax credits;
the refund of $98.1 million made in 2024 to Entergy New Orleans as a result of the settlement with the City Council. See Note 2 to the financial statements for discussion of the settlement with the City Council;
the refund of $92.7 million made in 2024 to Entergy Arkansas as a result of the settlement with the APSC. See Note 2 to the financial statements for discussion of the settlement with the APSC;
the refund of $80.2 million made in 2024 to Entergy Louisiana as a result of the settlement with the LPSC. See Note 2 to the financial statements for discussion of the settlement with the LPSC; and
a decrease of $16.8 million in spending on nuclear refueling outage costs in 2025 as compared to 2024.

The increase was partially offset by $174.4 million in payments to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in 2025 related to the net proceeds from the transfers of the 2024 nuclear production tax credits in accordance with the Unit Power Sales Agreement. See Note 3 to the financial statements for discussion of the nuclear production tax credits.

Investing Activities

Net cash flow used in investing activities decreased by $126.7 million in 2025 primarily due to a decrease in cash used of $99.1 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 a decrease of $32.7 million in nuclear construction expenditures primarily due to higher spending in 2024 on Grand Gulf outage projects and upgrades.

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Financing Activities

System Energy’s financing activities used $89.4 million of cash in 2025 compared to providing $315.3 million of cash in 2024 primarily due to the following activity:

the issuance of $300 million of 5.30% Series mortgage bonds in December 2024;
the repayment, prior to maturity, of $200 million of 2.14% Series mortgage bonds in June 2025;
a capital contribution of $150 million received from Entergy Corporation in January 2024 in order to maintain System Energy’s capital structure;
net repayments of $36.3 million in 2025 compared to net long-term borrowings of $51.2 million in 2024 on the nuclear fuel company variable interest entity’s credit facility;
money pool activity;
a decrease of $70 million in common stock dividends and distributions paid in 2025 in order to maintain System Energy’s capital structure; and
the issuance of $240 million of 5.30% Series mortgage bonds in May 2025.

Increases in System Energy’s payable to the money pool are a source of cash flow, and System Energy’s payable to the money pool increased $16.3 million in 2025 compared to decreasing by $12.2 million in 2024. 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 additional details of long-term debt.

2024 Compared to 2023

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Liquidity and Capital Resources - Cash Flow” in Item 7 of System Energy’s Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 18, 2025, for discussion of operating, investing, and financing cash flow activities for 2024 compared to 2023.

Capital Structure

System Energy’s debt to capital ratio is shown in the following table.


	December 31, 2025		December 31, 2024
Debt to capital	53.1	%	52.9	%
Effect of subtracting cash	—	%	(0.7	%)
Net debt to net capital (non-GAAP)	53.1	%	52.2	%

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. System Energy uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition. The net debt to net capital ratio is a non-GAAP measure. System Energy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition because net debt indicates System Energy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend or a capital distribution, to the extent funds are legally available to do so, or a combination of the three, in appropriate amounts to maintain the capital structure. To the extent that operating cash flows are insufficient to support planned investments and other uses of cash such as the payment of expenses in the ordinary course, System Energy may issue incremental debt or reduce dividends, or both, to maintain its capital structure. In addition, System Energy may receive equity contributions to maintain its capital structure for certain circumstances that would materially alter the capital structure if financed entirely with debt and reduced dividends.

Uses of Capital

System Energy requires capital resources for:

construction and other capital investments;
debt maturities or retirements;
working capital purposes, including the financing of fuel costs and tax payments; and
dividend, distribution, and interest payments.

Following are the amounts of System Energy’s planned construction and other capital investments.


	2026	2027	2028	2029
	(In Millions)
Planned construction and capital investment:
Generation	$130	$115	$135	$140
Utility Support	25	5	5	25
Total	$155	$120	$140	$165

In addition to routine spending to maintain operations, the planned capital investment estimate includes amounts associated with Grand Gulf investments and initiatives. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, governmental actions, including trade-related governmental actions discussed below, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital, including any changes to governmental programs, such as loans, grants, guarantees, and other subsidies.

Recent announcements of changes to international trade policy and tariffs and further similar changes may impact System Energy’s business, operations, results of operations, and liquidity and capital resources. Potential impacts may include increases in costs associated with System Energy’s capital investments or operation and maintenance expenses; operational impacts, such as supply chain, manufacturing, cost and availability of qualified, skilled labor, or raw materials sourcing disruptions which may affect System Energy’s ability to make planned capital investments as and when expected and needed; legal uncertainties, such as potential legal or other challenges to presidential tariff authority; or broader economic risks, including changes to domestic monetary policy, shifting customer demand, impacts on customer investment decisions, and volatile or uncertain credit and capital markets, which may affect System Energy’s ability to access needed capital. The nature and extent of any such effects will depend on, among other things, the specifics of the changes that are ultimately implemented both domestically and internationally, the responses of vendors, suppliers, and other counterparties to those changes, indirect effects on the price and availability of non-tariffed goods, and the effectiveness of mitigation measures.

System Energy has incurred incremental cost increases due to certain tariff-exposed inputs, including select equipment, components, or underlying raw materials. As of the date of this Form 10-K, such increases have not had a material effect on its current and planned capital projects. System Energy is not able to predict any further effects of such tariffs or the effects of potential changes in regulation and law, changes to governmental programs, such as

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

loans, grants, guarantees, and other subsidies, and trade-related governmental actions, such as tariffs and other measures, on its current and planned capital projects.

Following are the amounts of System Energy’s existing debt obligations (includes estimated interest payments).


	2026	2027	2028	2029-2030	After 2030
	(In Millions)
Long-term debt (a)	$71	$196	$378	$96	$865

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

Other Obligations

System Energy currently expects to contribute approximately $13.2 million to its qualified pension plans and approximately $49 thousand to its other postretirement plans in 2026, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026, valuations are completed, which is expected by April 1, 2026. 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.

System Energy has $140.9 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition, System Energy enters into nuclear fuel purchase agreements that contain minimum purchase obligations. As discussed in Note 8 to the financial statements, System Energy recovers these costs through charges under the Unit Power Sales Agreement.

As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.

Sources of Capital

System Energy’s sources to meet its capital requirements include:

internally generated funds;
cash on hand;
the Entergy system money pool;
debt issuances, including debt issuances to refund or retire currently outstanding or maturing indebtedness;
equity contributions; and
bank financing under new or existing facilities.

Circumstances such fuel and purchased power price fluctuations and unanticipated expenses, including unscheduled plant outages, could affect the timing and level of internally generated funds in the future. In addition to the financings necessary to meet capital requirements and contractual obligations, System Energy expects to continue, when economically feasible, to retire higher-cost debt and replace it with lower-cost debt if market conditions permit.

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

All debt issuances by System Energy require prior regulatory approval. Debt issuances are also subject to requirements set forth in its bond indenture and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs for the next twelve months and beyond.

System Energy’s receivables from (payables to) the money pool were as follows as of December 31 for each of the following years.


2025	2024	2023	2022
(In Thousands)
($16,299)	$2,851	($12,246)	$94,981

See Note 4 to the financial statements for a description of the money pool.

The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in June 2027. As of December 31, 2025, $36.4 million in loans were outstanding under the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.

System Energy obtained authorizations from the FERC through January 2027 for the following:

short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
long-term borrowings and security issuances; and
borrowings by its nuclear fuel company variable interest entity.

See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.

Federal Regulation

Complaints Against System Energy

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, and sold to Entergy Louisiana through September 30, 2025, pursuant to the Unit Power Sales Agreement. System Energy and the Unit Power Sales Agreement have been the subject of several litigation proceedings at the FERC, including challenges with respect to System Energy’s authorized return on equity and capital structure, renewal of its sale-leaseback arrangement, treatment of uncertain tax positions, a broader investigation of rates under the Unit Power Sales Agreement, and 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. Settlements that resolve all significant aspects of these complaints have been reached with the MPSC, the APSC, the City Council, and the LPSC, and these settlements have been approved by the FERC. See “Complaints Against System Energy” in Note 2 to the financial statements for discussion of these complaint proceedings and settlements.

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Unit Power Sales Agreement

System Energy Formula Rate Annual Protocols Formal Challenges Concerning 2020-2022 Calendar Year Bills

System Energy’s Unit Power Sales Agreement includes formula rate protocols that provide for the disclosure of cost inputs, an opportunity for informal discovery procedures, and a challenge process. In February 2022, pursuant to the protocols procedures, the LPSC, the APSC, the MPSC, the City Council, and the Mississippi Public Utilities Staff filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2020. In March 2023, pursuant to the protocols procedures discussed above, the LPSC, the APSC, and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2021. In February 2024, pursuant to the protocols procedures, the LPSC and the City Council filed with the FERC a formal challenge to System Energy’s implementation of the formula rate during calendar year 2022. These formal challenges were ultimately settled as a result of System Energy’s global settlements with the MPSC, the APSC, the City Council, and the LPSC. See “Complaints Against System Energy” in Note 2 to the financial statements for further discussion of the System Energy settlements with the MPSC, the APSC, the City Council, and the LPSC.

Depreciation Amendment Proceeding

In December 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to adopt updated rates for use in calculating Grand Gulf plant depreciation and amortization expenses. The proposed amendments would result in higher charges to the Utility operating companies that buy capacity and energy from System Energy under the Unit Power Sales Agreement. In February 2022 the FERC accepted System Energy’s proposed increased depreciation rates with an effective date of March 1, 2022, subject to refund pending the outcome of the settlement and/or hearing procedures. In June 2023 System Energy filed with the FERC an unopposed offer of settlement that it had negotiated with intervenors to the proceeding. In August 2023 the FERC approved the settlement, which resolves the proceeding. In third quarter 2023, System Energy recorded a reduction in depreciation expense of $41 million representing the cumulative difference in depreciation expense resulting from the depreciation rates used from March 2022 through June 2023 and the depreciation rates included in the settlement filing approved by the FERC. In October 2023, System Energy filed a refund report with the FERC. The refund provided for in the refund report was included in the September 2023 service month bills under the Unit Power Sales Agreement. No comments or protests to the refund report were filed.

Pension Costs Amendment Proceeding

In October 2021, System Energy submitted to the FERC proposed amendments to the Unit Power Sales Agreement to include in rate base the prepaid and accrued pension costs associated with System Energy’s qualified pension plans. Based on data ending in 2020, the increased annual revenue requirement associated with the filing is approximately $8.9 million. In March 2022 the FERC accepted System Energy’s proposed amendments with an effective date of December 1, 2021, subject to refund pending the outcome of the settlement and/or hearing procedures. In August 2023 the FERC chief ALJ terminated settlement procedures and designated a presiding ALJ to oversee hearing procedures. Testimony was filed by the parties from October 2023 through April 2024, and the hearing concluded in June 2024.

In September 2024 the presiding ALJ issued an initial decision recommending that the FERC approve inclusion of a line item in rate base for prepaid and accrued pension costs; however, the presiding ALJ did not agree with System Energy’s proposed methodology to calculate the value of the prepaid and accrued pension cost input. Instead, the presiding ALJ recommended limiting System Energy’s recovery to the prepaid and accrued pension costs that were incurred beginning in 2015 and later. The ALJ’s initial decision was not binding on the FERC and was an interim step in the hearing process.

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

System Energy disputed the presiding ALJ's determination concerning the methodology used to calculate the prepaid and accrued pension input, and System Energy filed exceptions to these rulings in October 2024. In October 2024, the LPSC, the APSC, and the FERC trial staff filed separate briefs on exceptions; these parties generally argue that the presiding ALJ should have rejected System Energy’s filing entirely, rather than limit System Energy’s recovery of the prepaid and accrued pension costs. Later in October 2024, System Energy, the LPSC, the APSC, and the FERC trial staff filed separate briefs opposing exceptions.

In November 2025 the FERC issued an order on the initial decision and reversed the ALJ’s decision. The FERC approved System Energy’s proposed prepaid and accrued pension recovery mechanism. System Energy has been utilizing this methodology in billings since December 1, 2022 and will continue to utilize it going forward. As a result of the FERC’s order, System Energy does not owe any refunds. In December 2025 the APSC filed a request for rehearing of the November 2025 order. In January 2026 the FERC denied the APSC’s rehearing request by operation of law. The FERC indicated that the APSC’s request for rehearing will be addressed substantively in a future order. This proceeding is not covered by the global settlements described in Note 2 to the financial statements.

Nuclear Matters

System Energy owns and, through an affiliate, operates the Grand Gulf nuclear generating plant and is, therefore, subject to the risks related to such ownership and operation. These include risks related to: the acquisition, 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 Grand Gulf to meet its operational goals; the performance and capacity factors of Grand Gulf; 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 the 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 Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf’s operating license expires in 2044.

Environmental Risks

System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations, with reference to possible exceptions noted in “Regulation of Entergy’s Business - Environmental Regulation” in Part I, Item 1. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of System Energy’s financial statements in conformity with 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 System Energy’s financial position, results of operations, or cash flows.

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Nuclear Decommissioning Costs

Utility Regulatory Accounting

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

System Energy’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are 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 2026 Qualified Pension Cost	Impact on 2025 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$197	$6,054
Rate of return on plan assets	(0.25%)	$704	$—
Rate of increase in compensation	0.25%	$245	$1,138

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 2026 Postretirement Benefits Cost	Impact on 2025 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$49	$963
Health care cost trend	0.25%	$51	$548

Each fluctuation above assumes that the other components of the calculation are held constant.

System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Costs and Employer Contributions

Total qualified pension cost for System Energy in 2025 was $5.9 million, including $512 thousand in settlement costs. System Energy anticipates 2026 qualified pension cost to be $4.4 million. System Energy contributed $15.7 million to its qualified pension plans in 2025 and estimates 2026 pension contributions will be approximately $13.2 million, although the 2026 required pension contributions will be known with more certainty when the January 1, 2026 valuations are completed, which is expected by April 1, 2026.

Total postretirement health care and life insurance benefit income for System Energy in 2025 was $855 thousand. System Energy expects 2026 postretirement health care and life insurance benefit income to approximate $257 thousand. System Energy contributed $1.2 million to its other postretirement plans in 2025 and expects 2026 contributions to approximate $49 thousand.

Other Contingencies

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 shareholder and Board of Directors of

System Energy Resources, Inc.

Opinion on the Financial Statements

We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 2025 and 2024, the related statements of income, cash flows, and changes in common equity (pages 467 through 472 and applicable items in pages 53 through 246), for each of the three years in the period ended December 31, 2025, 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, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that is material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.

Rate and Regulatory Matters — System Energy Resources, Inc. — Refer to Note 2 to the financial statements

Critical Audit Matter Description

The Company is subject to wholesale rate regulation by the Federal Energy Regulatory Commission (“FERC”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures.

The Company’s rates are subject to regulatory rate-setting processes and annual earnings oversight. Because the FERC sets the rates the Company is allowed to charge customers based on allowable costs, including a reasonable return on equity, the Company applies accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. The Company assesses whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in applicable regulatory and political environments. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the FERC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of amounts invested in the utility business and a reasonable return on that investment.

We identified the impact of rate regulation as a critical audit matter due to the 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 the likelihood of refunds to customers. Auditing management’s judgments regarding the outcome of future decisions by 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 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 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 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 and intervenors’ filings with the FERC and FERC orders issued 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 refund 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 19, 2026

We have served as the Company’s auditor since 2001.


SYSTEM ENERGY RESOURCES, INC.
INCOME STATEMENTS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING REVENUES
Electric	$581,481	$585,049	$586,603

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	64,507	62,433	71,762
Nuclear refueling outage expenses	16,614	19,158	26,745
Other operation and maintenance	189,628	192,300	207,765
Decommissioning	45,255	43,478	41,773
Taxes other than income taxes	26,868	27,260	29,224
Depreciation and amortization	123,846	121,386	90,858
Other regulatory charges (credits) - net	2,453	(2,799)	(57,429)
TOTAL	469,171	463,216	410,698

OPERATING INCOME	112,310	121,833	175,905

OTHER INCOME
Allowance for equity funds used during construction	8,342	7,647	7,531
Interest and investment income	54,971	47,953	13,131
Miscellaneous - net	106	672	(9,101)
TOTAL	63,419	56,272	11,561

INTEREST EXPENSE
Interest expense	72,148	48,121	48,416
Allowance for borrowed funds used during construction	(4,089)	(3,019)	(1,754)
TOTAL	68,059	45,102	46,662

INCOME BEFORE INCOME TAXES	107,670	133,003	140,804

Income taxes	19,575	29,503	32,032

NET INCOME	$88,095	$103,500	$108,772

See Notes to Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2025	2024	2023
	(In Thousands)

OPERATING ACTIVITIES
Net income	$88,095	$103,500	$108,772
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	225,844	217,250	195,045
Deferred income taxes, tax credits, and non-current taxes accrued	153,647	41,142	32,982
Changes in assets and liabilities:
Receivables	(21,208)	10,697	8,359
Accounts payable	(9,231)	(89,911)	78,655
Taxes accrued	(4,167)	(11,549)	19,804
Interest accrued	(127)	388	1,363
Other working capital accounts	1,580	(15,353)	20,749
Other regulatory assets	(174,691)	19,866	(31,239)
Other regulatory liabilities	144,604	(37,713)	11,009
Pension and other postretirement funded status	(20,947)	(30,717)	(21,259)
Other assets and liabilities	(131,659)	(176,095)	(150,668)
Net cash flow provided by operating activities	251,740	31,505	273,572
INVESTING ACTIVITIES
Construction expenditures	(138,849)	(174,257)	(121,075)
Allowance for equity funds used during construction	8,342	7,647	7,531
Nuclear fuel purchases	(73,471)	(145,567)	(80,663)
Proceeds from sale of nuclear fuel	43,549	16,531	46,242
Decrease (increase) in other investments	—	23	(3)
Proceeds from nuclear decommissioning trust fund sales	613,146	901,239	390,004
Investment in nuclear decommissioning trust funds	(646,797)	(920,700)	(412,823)
Changes in money pool receivable - net	2,851	(2,851)	94,981
Net cash flow used in investing activities	(191,229)	(317,935)	(75,806)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	764,028	1,325,581	715,545
Retirement of long-term debt	(769,690)	(978,057)	(758,437)
Capital contribution from parent	—	150,000	—
Changes in money pool payable - net	16,299	(12,246)	12,246
Common stock dividends and distributions paid	(100,000)	(170,000)	(170,000)
Net cash flow provided by (used in) financing activities	(89,363)	315,278	(200,646)
Net increase (decrease) in cash and cash equivalents	(28,852)	28,848	(2,880)
Cash and cash equivalents at beginning of period	28,908	60	2,940
Cash and cash equivalents at end of period	$56	$28,908	$60
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized	$64,252	$57,599	$45,196
Income taxes - net (includes production tax credit sale proceeds of $133,752 in 2025, $— in 2024, and $— in 2023)	($131,297)	$624	($19,810)
Noncash investing activities:
Accrued construction expenditures	$16,830	$6,290	$25,301

See Notes to Financial Statements.


SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS

	December 31,
	2025	2024
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash	$56	$448
Temporary cash investments	—	28,460
Total cash and cash equivalents	56	28,908
Accounts receivable:
Associated companies	65,083	48,134
Other	6,833	5,425
Total accounts receivable	71,916	53,559
Materials and supplies	149,847	163,814
Deferred nuclear refueling outage costs	9,096	19,884

Prepayments and other	5,101	5,768
TOTAL	236,016	271,933

OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds	1,730,722	1,529,059
TOTAL	1,730,722	1,529,059

UTILITY PLANT
Electric	5,753,963	5,668,253
Construction work in progress	123,172	85,127
Nuclear fuel	208,932	220,044
TOTAL UTILITY PLANT	6,086,067	5,973,424
Less - accumulated depreciation and amortization	3,679,886	3,578,709
UTILITY PLANT - NET	2,406,181	2,394,715

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Other regulatory assets	601,185	426,494

Other	34,301	20,273
TOTAL	635,486	446,767

TOTAL ASSETS	$5,008,405	$4,642,474

See Notes to Financial Statements.


SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2025	2024
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt	$140	$200,090
Accounts payable:
Associated companies	25,528	18,477
Other	66,611	45,017
Taxes accrued	11,685	15,852
Interest accrued	13,215	13,342
Other	4,089	4,473
TOTAL	121,268	297,251

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	625,165	451,830
Accumulated deferred investment tax credits	43,045	42,984
Regulatory liability for income taxes - net	99,960	105,467
Other regulatory liabilities	897,301	747,190
Decommissioning	1,172,967	1,127,712

Long-term debt	1,088,563	889,646
Other	2	8,355
TOTAL	3,927,003	3,373,184

Commitments and Contingencies

COMMON EQUITY
Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2025 and 2024	908,944	958,944
Retained earnings	51,190	13,095
TOTAL	960,134	972,039

TOTAL LIABILITIES AND EQUITY	$5,008,405	$4,642,474

See Notes to Financial Statements.


SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2025, 2024, and 2023

	Common Stock	Retained Earnings (Accumulated Deficit)	Total
	(In Thousands)

Balance at December 31, 2022	$1,086,850	($137,083)	$949,767
Net income	—	108,772	108,772
Common stock dividends and distributions	(170,000)	—	(170,000)

Balance at December 31, 2023	$916,850	($28,311)	$888,539
Net income	—	103,500	103,500
Capital contributions from parent	150,000	—	150,000
Common stock dividends and distributions	(107,906)	(62,094)	(170,000)
Balance at December 31, 2024	$958,944	$13,095	$972,039
Net income	—	88,095	88,095

Common stock dividends and distributions	(50,000)	(50,000)	(100,000)
Balance at December 31, 2025	$908,944	$51,190	$960,134

See Notes to Financial Statements.

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