ENTERGY ARKANSAS, LLC

ENTERGY TEXAS, INC. AND SUBSIDIARIES

Net income increased $46.8 million primarily due to higher volume/weather, higher retail electric price, and higher other income, partially offset by higher taxes other than income taxes, higher interest expense, higher unrecovered capacity costs in 2026, and higher other operation and maintenance expenses.

Net income increased $65.2 million primarily due to higher volume/weather, higher retail electric price, higher other income, and higher unrecovered capacity costs in 2025, partially offset by higher other operation and maintenance expenses, higher taxes other than income taxes, and higher interest expense.

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 volume/weather variance is primarily due toan increase in industrial usage, an increase in weather-adjusted residential usage, andthe 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 agricultural and other chemicals, transportation, and petrochemicals customers. The increase in weather-adjusted residential usage is primarily due to an increase in customers.

The retail electric price variance is primarily due to increases in the distribution cost recovery factor rider effective December 2025 and July 2026 and an increase in the transmission cost recovery factor rider effective April 2026. See Note 2 to the financial statements herein and in the Form 10-K for discussion of the distribution and transmission cost recovery factor rider filings.

Total electric energy sales for Entergy Texas for the three months ended September 30, 2026 and 2025 are as follows:

See Note 12 to the financial statements herein for additional discussion of Entergy Texas’s operating revenues.

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 volume/weather variance is primarily due toan increase in industrial usage and an increase in weather-adjusted residential usage, partially offset bythe effect of less favorable weather on residential sales. The increase in industrial usage is primarily due to an increase in demand from large industrial customers, primarily agricultural and other chemicals, transportation, and industrial gases customers. The increase in weather-adjusted residential usage is primarily due to an increase in customers.

The retail electric price variance is primarily due to increases in the distribution cost recovery factor rider effective June 2025, December 2025, and July 2026 and an increase in the transmission cost recovery factor rider effective April 2026. See Note 2 to the financial statements herein and in the Form 10-K for discussion of the distribution and transmission cost recovery factor rider filings.

Total electric energy sales for Entergy Texas for the nine months ended September 30, 2026 and 2025 are as follows:

See Note 12 to the financial statements herein for additional discussion of Entergy Texas’s operating revenues.

•$14.6 million of unrecovered capacity cost charges in 2026 under a new short-term, one-year power purchase agreement beginning in June 2026; and

•$11.5 million of higher unrecovered costs in 2025 related to the procurement of capacity through MISO’s annual planning resource auction. Higher costs in third quarter 2025 resulted from the effect of a significant increase in MISO’s seasonal auction clearing price, due to the implementation of a reliability-based demand curve, for capacity transactions during the summer months in 2025. Prior to June 2026, Entergy Texas also did 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. In May 2026, Entergy Texas filed a request with the PUCT for a capacity cost recovery rider to recover eligible capacity procurement costs associated with its participation in MISO’s annual planning resource auction, and the PUCT approved the request in July 2026. See Note 2 to the financial statements herein for discussion of the capacity cost recovery rider.

Other operation and maintenance expenses increased primarily due to an increase of $1.7 million in energy efficiency expenses primarily due to the timing of recovery from customers and several individually insignificant items. The increase was partially offset by a decrease of $1.6 million in loss provisions and a decrease of $1.4 million in bad debt expense.

Other income increased primarily due to higher interest earned on money pool investments and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2026, including the Orange County Advanced Power Station project and the Lone Star Power Station project, partially offset by lower construction work in progress in 2026 on the Legend Power Station project as a result of the sale of assets related to the in-process project in December 2025. See Note 8 to the financial statements in the Form 10-K for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station.

Interest expense increased primarily due to the issuance of $425 million of 5.20% Series mortgage bonds in May 2026.

•$27.2 million of higher unrecovered costs in 2025 related to the procurement of capacity through MISO’s annual planning resource auction. Higher costs in 2025 resulted from the effect of a significant increase in MISO’s seasonal auction clearing price, due to the implementation of a reliability-based demand curve, for capacity transactions during the summer months in 2025. Prior to June 2026, Entergy Texas also did 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. In May 2026, Entergy Texas filed a request with the PUCT for a capacity cost recovery rider to recover eligible capacity procurement costs associated with its participation in MISO’s annual planning resource auction, and the PUCT approved the request in July 2026. See Note 2 to the financial statements herein for discussion of the capacity cost recovery rider; and

•$19.4 million of unrecovered capacity cost charges in 2026 under a new short-term, one-year power purchase agreement beginning in June 2026.

•an increase of $2.6 million in energy efficiency expenses primarily due to the timing of recovery from customers;

•an increase of $2.2 millionin compensation and benefits costs primarily due to higher healthcare claims activity, the timing of the recognition of prescription drug rebates, and a larger revision to estimated incentive-based compensation expense in 2025;

•an increase of $2.1 million in power delivery expenses primarily due to higher vegetation maintenance costs and increased contract labor costs;

•an increase of $1.9 million in insurance expense primarily due to higher premiums in 2026 as compared to 2025;

•an increase of $1.5 million in transmission costs allocated by MISO; and

The increase was partially offset by a decrease of $7.5 million in bad debt expense and a decrease of $1.5 million in loss provisions.

Other income increased primarily due to higher interest earned on money pool investments and an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2026, including the Orange County Advanced Power Station project and the Lone Star Power Station project, partially offset by lower construction work in progress in 2026 on the Legend Power Station project as a result of the sale of assets related to the in-process project in December 2025. See Note 8 to the financial statements in the Form 10-K for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station.

Interest expense increased primarily due to the issuance of $425 million of 5.20% Series mortgage bonds in May 2026 and the issuance of $500 million of 5.25% Series mortgage bonds in February 2025, partially offset by lower carrying costs on the deferred fuel balance.

The effective income tax rates were 18.9% for the third quarter 2026 and 18.0% for thenine months ended September 30, 2026. The differences in the effective income tax rates for thethird quarter 2026 and thenine months ended September 30, 2026 versus the federal statutory rate of 21% were primarily due to book and tax differences related to the allowance for equity funds used during construction and certain book and tax differences related to utility plant items.

The effective income tax rates were 18.3% for the third quarter 2025 and 17.2% for the nine months ended September 30, 2025. The differences in the effective income tax ratesfor the third quarter 2025 and thenine months ended September 30, 2025 versus the federal statutory rate of 21% were primarily due to book and tax differences related to the allowance for equity funds used during construction.

Net cash flow provided by operating activities increased $83.0 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to higher collections from customers, partially offset by higher fuel and purchased power payments and the timing of payments to vendors. See Note 2 to the financial statements herein and in the Form 10-K for a discussion of fuel and purchased power cost recovery.

Net cash flow used in investing activities decreased$449.2 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to a decrease of $408.2 million in non-nuclear generation construction expenditures primarily due to lower spending on the Legend Power Station project as a result of the sale of assets related to the in-process project in December 2025 and lower spending on the Orange County Advanced Power Station project in 2026 and a decrease of $95.1 million in transmission construction expenditures primarily due to decreased spending on various transmission projects in 2026. The decrease was partially offset by 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 and money pool activity. See Note 8 to the financial statements in the Form 10-K for discussion of the Entergy Texas build-to-suit lease arrangement for the Legend Power Station.

Decreases in Entergy Texas’s receivable from the money pool are a source of cash flow, and Entergy Texas’s receivable from the money pool decreased $6.2 million for the nine months ended September 30, 2026 compared to decreasing by $18.5 million for the nine months ended September 30, 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.

Net cash flow provided by financing activities decreased $210.5 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to:

•the issuance of $500 million of 5.25% Series mortgage bonds in February 2025;

•a $248.3 million payment in June 2026 associated with a financed portion of construction work in progress related to the Orange County Advanced Power Station;

•the repayment of $130 million of 1.50% Series mortgage bonds in September 2026; and

The decrease was partially offset by the issuance of $425 million of 5.20% Series mortgage bonds in May 2026 and a capital contribution of $365 million received from Entergy Corporation in 2026 in order to maintain Entergy Texas’s capital structure and in anticipation of various capital expenditures.

Increases in Entergy Texas’s payable to the money pool are a source of cash flow, and Entergy Texas’s payable to the money pool increased by $142.2 million for the nine months ended September 30, 2025.

Entergy Texas’s debt to capital ratio is shown in the following table. The decrease in the debt to capital ratio for Entergy Texas is primarily due to a capital contribution of $365 million received from Entergy Corporation in 2026.

(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 in the Form 10-K. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS -Liquidity and Capital Resources” in the Form 10-K for a discussion of Entergy Texas’s uses and sources of capital. The following are updates to the information provided in the Form 10-K.

Entergy Texas is developing its capital investment plan for 2027 through 2030 and currently anticipates making the following construction and other capital investments during that period:

In addition to routine capital spending to maintain operations, the capital plan for Entergy Texas includes investments in generation projects to modernize, decarbonize, expand, and diversify Entergy Texas’s portfolio, including 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 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 policies and actions, including trade-related governmental actions, such as tariffs, executive orders, and other measures, including Executive Order 14421 and the Section 232 Proclamation, environmental regulations, 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 governmental policies and actions, such as tariffs, executive orders, and other measures, including Executive Order 14421 and the Section 232 Proclamation, on its current and planned capital projects, including project delays, modifications, and cost increases.

Entergy Texas’s receivables from or (payables to) the money pool were as follows:

Entergy Texas has a credit facility in the amount of $300 million scheduled to expire in June 2031. 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 September 30, 2026, 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 September 30, 2026, $95.1 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 herein for additional discussion of the credit facilities.

Cypress to Legend 500 kV Transmission Line

As discussed in the Form 10-K, 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 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 345 th 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 petitioners assert was not adequately noticed. In March 2026, Entergy Texas and the PUCT filed answers disputing all aspects of the petition. In April 2026 petitioners filed an amended petition with minor adjustments to their original petition. In May 2026 petitioners filed a supplemental application for temporary injunction and opposition to pleas to the jurisdiction in response to jurisdictional defenses raised in the answers filed by Entergy Texas and the PUCT. In June 2026 the court set a hearing for July 2026 on petitioners’ requested temporary injunction and any pleas to the jurisdiction and motions for summary judgment. In June 2026 the PUCT filed its plea to the jurisdiction. In June 2026 petitioners filed a motion for summary judgment and Entergy Texas filed an amended answer addressing the amended petition, a plea to the jurisdiction, and, in the alternative, a motion for summary judgment. In July 2026 the court issued a written order granting Entergy Texas’s and the PUCT’s pleas to the jurisdiction and, in the alternative, Entergy Texas’s motion for summary judgment. In August 2026 petitioners filed a notice of appeal to the Fifteenth Court of Appeals. In October 2026 the appellate record was filed with the Fifteenth Court of Appeals, triggering a 30-day deadline for the appellants to file a brief on the merits. Also in October 2026, the appellants filed a motion for temporary relief requesting that Entergy Texas be restrained from exercising eminent domain and construction activities on the appellants’ properties. Entergy Texas expects to respond in opposition to the motion for temporary relief by the November 2026 deadline established by the court. Subject to receipt of required permits and other conditions, the project is expected to be in service by the end of 2028.

Forest to War Eagle to Porter 138 kV Transmission Line

In August 2026, 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 138 kV transmission line. The transmission line is expected to be approximately 9 to 11 miles in length and the estimated cost of the project ranges from $88.8 million to $99.4 million, depending on the route ultimately approved by the PUCT. Also in August 2026, the PUCT referred the proceeding to the State Office of Administrative Hearings. In September 2026 the ALJ with the State Office of Administrative Hearings adopted a procedural schedule that set a hearing for November 2026. In October 2026 the PUCT staff filed direct testimony recommending the PUCT approve Entergy Texas’s application and identifying the proposed route it concluded to best meet the statutory criteria for certification. The statutory deadline for a PUCT decision is February 2027.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - State and Local Rate Regulation and Fuel-Cost Recovery” in the Form 10-K for a discussion of state and local rate regulation and fuel-cost recovery. The following are updates to that discussion.

Distribution Cost Recovery Factor (DCRF) Rider

In April 2026, 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 $112.5 million annually, or $20.4 million in incremental annual revenues beyond Entergy Texas’s then-effective DCRF rider based on its capital invested in distribution between July 1, 2025 and December 31, 2025. In July 2026 the PUCT approved the DCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective for usage on and after July 8, 2026.

In September 2026, Entergy Texas filed with the PUCT a request to amend its DCRF rider. The proposed rider is designed to collect from Entergy Texas’s retail customers approximately $127.3 million annually, or $14.8 million in incremental annual revenues beyond Entergy Texas’s currently effective DCRF rider based on its capital invested in distribution between January 1, 2026 and June 30, 2026. In September 2026 the ALJ with the State Office of Administrative Hearings adopted a procedural schedule requiring the PUCT staff to file a recommendation on the merits of Entergy Texas’s application by November 2, 2026.

Transmission Cost Recovery Factor (TCRF) Rider

As discussed in the Form 10-K, in October 2025, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The amended rider was designed to collect from Entergy Texas’s retail customers approximately $30.3 million annually, or $20.6 million in incremental annual revenues beyond Entergy Texas’s then-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 April 2026 the PUCT approved the TCRF rider, consistent with Entergy Texas’s as-filed request, and rates became effective for usage on and after April 6, 2026.

In October 2026, 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 $56.7 million annually, or $26.4 million in incremental annual revenues beyond Entergy Texas’s currently effective TCRF rider based on its capital invested in transmission between July 1, 2025 and June 30, 2026 and changes in other transmission charges.

Generation Cost Recovery Rider

In March 2026, Entergy Texas filed an application to establish a generation cost recovery rider to begin recovering a return of and on its capital investment in the Orange County Advanced Power Station. The proposed generation cost recovery rider, which includes Entergy Texas’s capital invested in generation for the Orange County Advanced Power Station through December 31, 2025, was designed to collect approximately $150.4 million annually from Entergy Texas’s retail customers. In July 2026 the ALJ with the State Office of Administrative Hearings approved aproposed procedural schedule that included a hearing on the merits in September 2026 and provided for interim rates to become effective for usage on and after the Orange County Advanced Power Station in-service date, to the extent final rates were not in place by that time. In September 2026, Entergy Texas filed, and the ALJ with the State Office of Administrative Hearings granted, a joint motion to abate the procedural schedule and cancel the hearing on the merits to give the parties to the proceeding additional time to finalize a settlement. Interim rates became effective when the Orange County Advanced Power Station was placed into service in October 2026. Also in October 2026, Entergy Texas filed an unopposed stipulation resolving all issues in case, supporting testimony, a joint motion to adjust the interim rates previously implemented to correspond to the stipulated revenue requirement, and a joint motion to admit evidence and remand the proceeding to the PUCT. The unopposed stipulation would result in no disallowance of recoverable investment but would reduce the annual revenue requirement collected through the generation cost recovery rider by $5.7 million while the rider remains in effect. The PUCT is expected to issue a final order on the settlement by the end of 2026.

In September 2026, Entergy Texas filed an application with the PUCT to reconcile its fuel and purchased power costs for the period from April 2024 through March 2026. During the reconciliation period, Entergy Texas incurred approximately $1.2 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 over-recovery balance for the reconciliation period was approximately $90.1 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 2026.

Capacity Cost Recovery Rider (CCRR)

In May 2026, Entergy Texas filed with the PUCT a request to establish a new CCRR. The new CCRR was designed to collect approximately $58 million annually from Entergy Texas’s retail customers based on Entergy Texas’s eligible capacity-related costs and revenues for the 12 months beginning June 1, 2026. The eligible capacity-related costs and revenues are associated with Entergy Texas’s participation in MISO’s annual planning resource auction. In July 2026 the PUCT approved the CCRR, consistent with Entergy Texas’s as-filed request, and rates became effective on July 10, 2026.

Frontier Power Purchase Agreement

In June 2026, Entergy Texas filed an application for PUCT pre-approval of a long-term 14-year PPA for 300 MW of capacity and energy from the Tenaska Frontier Generating Station, an 830 MW natural gas-fired combined-cycle combustion turbine plant in Grimes County, Texas. As a result of accelerated load growth in Texas and other factors in Entergy Texas’s service territory, Entergy Texas has a significant near- and long-term need for capacity and energy to serve its customers. Within the application, Entergy Texas requested the PUCT find that the PPA will satisfy Entergy Texas’s identified reliability needs in allowing for cost recovery of the associated purchased power. The 14-year PPA has a total estimated cost of $883 million. In September 2026 the ALJ with the State Office of Administrative Hearings adopted a procedural schedule with a hearing on the merits scheduled in October 2026. In October 2026, Entergy Texas filed on behalf of the parties a joint motion to abate the procedural schedule noting that the parties had reached a settlement in principle and the ALJ with the State Office of Administrative Hearings approved the joint motion to allow the parties time to finalize the settlement.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Federal Regulation” in the Form 10-K and Note 2 to the financial statements herein and in the Form 10-K for a discussion of federal regulation.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” in the Form 10-K for a discussion of the estimates and judgments necessary in Entergy Texas’s accounting for utility regulatory accounting, taxation and uncertain tax positions, qualified pension and other postretirement benefits, and other contingencies.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements in the Form 10-K for a discussion of new accounting pronouncements and the “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis herein for updates to the discussion of new accounting pronouncements.

SYSTEM ENERGY RESOURCES, INC.

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. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues.

Net income increased $1.7 million primarily due to higher operating revenues resulting from changes in rate base.

Net income increased $3.4 million primarily due to higher operating revenues resulting from changes in rate base.

The effective income tax rates were 16.8% for the third quarter 2026 and 16.7% for the nine months ended September 30, 2026. The differences in the effective income tax rates for the third quarter 2026 and the nine months ended September 30, 2026 versus the federal statutory rate of 21% were primarily due to certain book and tax differences related to utility plant items, book and tax differences related to the allowance for equity funds used during construction, and the amortization of investment tax credits, partially offset by the accrual for state income taxes.

The effective income tax rate was 21.1% for the third quarter 2025. The difference in the effective income tax rate for the third quarter 2025 versus the federal statutory rate of 21% was primarily due to the accrual for state income taxes, substantially offset by certain book and tax differences related to utility plant items and book and tax differences related to the allowance for equity funds used during construction.

The effective income tax rate was 20.6% for the nine months ended September 30, 2025. The difference in the effective income tax rate for the nine months ended September 30, 2025 versus the federal statutory rate of 21% was primarily due to certain book and tax differences related to utility plant items and book and tax differences related to the allowance for equity funds used during construction, substantially offset by the accrual for state income taxes.

Net cash flow provided by operating activities decreased $71.9 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to an increase of $30.3 million in spending on nuclear refueling outage costs in 2026 as compared to 2025 andthe receipt of $68.8 million in proceeds from the transfer of 2025 nuclear production tax credits to third parties in 2026 as compared to the receipt of $98.7 million in proceeds from the transfer of 2024 nuclear production tax credits to third parties in 2025. See Note 10 to the financial statements herein and Note 3 to the financial statements in the Form 10-K for discussion of the nuclear production tax credits.

Net cash flow used in investing activities increased $107.8 million for the nine months ended September 30, 2026 compared to the nine months ended September 30, 2025 primarily due to an increase of $108.2 million in cash used 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, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle and an increase of $49.2 million in nuclear construction expenditures primarily due to higher spending in 2026 on Grand Gulf outage projects and upgrades. The increase was partially offset by money pool activity and a decrease of $17.1 million in decommissioning trust fund investment activity.

Increases in System Energy’s receivable from the money pool are a use of cash flow, and System Energy’s receivable from the money pool increased $1.2 million for the nine months ended September 30, 2026 compared to increasing by $30.3 million for the nine months ended September 30, 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.

System Energy’s financing activities provided $29.8 million of cash for the nine months ended September 30, 2026 compared to using $82.4 million of cash for the nine months ended September 30, 2025 primarily due to the following activity:

•the issuance of $80 million of 5.28% Series L notes by the System Energy nuclear fuel company variable interest entity in January 2026;

•a decrease of $45 million in common stock dividends and distributions paid in 2026 in order to maintain System Energy’s capital structure;

•net long-term borrowings of $1.5 million in 2026 compared to net repayments of $33.1 million in 2025 on the nuclear fuel company variable interest entity’s credit facility;

•the repayment, prior to maturity, of $200 million of 2.14% Series mortgage bonds in June 2025;

•the issuance of $240 million of 5.30% Series mortgage bonds in May 2025; and

Decreases in System Energy’s payable to the money pool are a use of cash flow, and System Energy’s payable to the money pool decreased $16.3 million for the nine months ended September 30, 2026.

System Energy’s debt to capital ratio is shown in the following table. The increase in the debt to capital ratio for System Energy is primarily due to the net issuance of long-term debt in 2026.

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 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 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.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS -Liquidity and Capital Resources” in the Form 10-K for a discussion of System Energy’s uses and sources of capital. The following are updates to the information provided in the Form 10-K.

System Energy is developing its capital investment plan for 2027 through 2030 and currently anticipates making the following construction and other capital investments during that period:

In addition to routine capital spending to maintain operations, the capital plan for System Energy 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 policies and actions, including trade-related governmental actions, such as tariffs, executive orders, and other measures, including Executive Order 14421 and the Section 232 Proclamation, environmental regulations, 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. System Energy 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 governmental policies and actions, such as tariffs, executive orders, and other measures, including Executive Order 14421 and the Section 232 Proclamation, on its current and planned capital projects, including project delays, modifications, and cost increases.

System Energy’s receivables from or (payables to) the money pool were as follows:

The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in June 2029. As of September 30, 2026, $37.9 million in loans were outstanding under the System Energy nuclear fuel company variable interest entity credit facility. See Note 4 to the financial statements herein for additional discussion of the variable interest entity credit facility.

See the “Rate, Cost-recovery, and Other Regulation -Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis in the Form 10-K and Note 2 to the financial statements herein and in the Form 10-K for a discussion of federal regulation. The following is an update to that discussion.

Unit Power Sales Agreement

See Note 2 to the financial statements in the Form 10-K for discussion of the Unit Power Sales Agreement. The following is an update to that discussion.

Pension Costs Amendment Proceeding

As discussed in the Form 10-K, 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. In November 2025 the FERC issued an order approving 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 did 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. In May 2026 the FERC issued a follow-up substantive order denying the APSC’s rehearing and sustaining its finding that no refunds are owed.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Nuclear Matters” in the Form 10-K for a discussion of nuclear matters. The following is an update to that discussion.

The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, “multiple/repetitive degraded cornerstone column,” or Column 4, and “unacceptable performance,” or Column 5. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Continued plant operation is not permitted for plants in Column 5. Grand Gulf is currently in Column 2.

In April 2026 the NRC issued a final significance determination and notice of violation for Grand Gulf, in which it finalized a “white” finding with “low safety significance” related to one of Grand Gulf’s emergency diesel generators, resulting in Grand Gulf’s placement in Column 2, effective first quarter 2026. In September 2026, Grand Gulf successfully completed an NRC supplemental inspection related to the emergency diesel generator issue. The NRC is expected to issue an inspection report in fourth quarter 2026 documenting Grand Gulf’s return to Column 1, effective third quarter 2026.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS – Environmental Risks” in the Form 10-K for a discussion of environmental risks.

See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates” in the Form 10-K for a discussion of the estimates and judgments necessary in System Energy’s accounting for nuclear decommissioning costs, utility regulatory accounting, taxation and uncertain tax positions, qualified pension and other postretirement benefits, and other contingencies.

See the “New Accounting Pronouncements” section of Note 1 to the financial statements in the Form 10-K for a discussion of new accounting pronouncements and the “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis herein for updates to the discussion of new accounting pronouncements.