Slides
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0 3Q 2026 earnings call Nov. 2, 2026
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1 Caution regarding forward-looking statements and Regulation G compliance This presentation contains certain “forward-looking statements” within the meaning of federal securities laws that are subject to risks and uncertainties. Such statements include, among other things, statements regarding Entergy’s adjusted earnings per share guidance and outlooks; the company’s capital plan; retail and industrial sales growth outlooks; other financial and operational outlooks; and other statements of Entergy’s plans, beliefs, or expectations within this presentation. Readers are cautioned not to place undue reliance on these forward- looking statements, which apply only as of the date of this presentation. Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Forward-looking statements are subject to a number of risks, uncertainties, and other factors that could cause actual results to differ materially from those expressed or implied in such forward-looking statements, including (a) those factors discussed elsewhere in this presentation and in Entergy’s most recent Annual Report on Form 10-K and any subsequent public filings with the Securities and Exchange Commission; (b) uncertainties associated with (1) rate proceedings, formula rate plans, and other cost recovery mechanisms, including the risk that costs may not be recoverable to the extent or on the timeline anticipated and (2) implementation of the ratemaking effects of changes in law; (c) uncertainties associated with (1) realizing the benefits of its resilience plan, including impacts of the frequency and intensity of future storms and storm paths, as well as the pace of project completion and (2) efforts to remediate the effects of major storms and recover related restoration costs; (d) risks associated with operating nuclear facilities, including plant relicensing, operating, and regulatory costs and risks; (e) changes in decommissioning trust values or earnings or in the timing or cost of decommissioning Entergy’s nuclear plant sites; (f) legislative and regulatory actions and risks and uncertainties associated with claims or litigation by or against Entergy and its subsidiaries; (g) risks and uncertainties associated with executing on business strategies, including (1) strategic transactions that Entergy or its subsidiaries may undertake and the risks that any such transaction may not be completed as and when expected or the anticipated benefits may not be realized, and (2) Entergy’s ability to meet the rapidly growing demand for electricity, including from large-scale data centers and other large customers, and to manage the impacts of such growth on customers and its business, or the risk that contracted or expected load growth does not materialize or is not sustained; (h) risks and uncertainties associated with the resolution of pending or future applications, regulatory proceedings, litigation or governmental official actions relating to generation, transmission, or other facilities and the effect of related public and political opposition, including, in each case, those relating to any facilities designed to serve large-scale data centers; (i) direct and indirect impacts to Entergy or its customers from pandemics, terrorist attacks, geopolitical conflicts, cybersecurity threats, data security breaches, or other attempts to disrupt Entergy’s business or operations, and/or other catastrophic events; and (j) effects on Entergy or its customers of (1) changes in federal, state, or local laws and regulations and other governmental actions or policies, such as changes in monetary, fiscal, trade, tax, environmental, or energy (including, among other things, data center energy use, efficiency standards, and sources of power) policies, as well as changes in utility regulations, including those relating to new projects designed to serve the increased load growth of large-scale data centers and other large customers; (2) changes in commodity markets, capital markets, or economic conditions; and (3) technological change, including the costs, pace of development, and commercialization of new and emerging technologies. This presentation includes the non-GAAP financial measures of adjusted EPS; adjusted ROE; and adjusted ROE, excluding affiliate preferred when describing Entergy’s results of operations and financial performance. We have prepared reconciliations of these financial measures to the most directly comparable GAAP measure, which can be found in this presentation. This presentation should be considered together with the Entergy earnings release to which this teleconference relates, which is posted on the company’s website at investors.entergy.com/investors/events-and-presentations/ and which contains further information on non-GAAP financial measures. 1
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2 Section Slides Business discussion 3–8 Appendix About Entergy 10 Utility 11–37 Financial disclosures 38–40 Financial summaries and Regulation G reconciliations 41–45 Table of contents
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3 Highlights See Financial summaries and Regulation G reconciliations section for earnings summary Key messages – 3Q results reflect strong sales, including the effects of warm weather – Continued progress on customer growth with a data center expansion in Arkansas that brings additional benefits to customers and communities – Narrowed 2026 adjusted EPS guidance and affirmed longer-term outlooks; continue to expect greater than 8% CAGR through 2030 – Upside opportunities from strong pipeline of customer interest and potential for additional customer-led investments – Strategic and financial plans to be discussed at EEI financial conference 3Q26 adjusted EPS $1.98 3Q26 OCF $2.2B
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4 3Q adjusted earnings per share Calculations may differ due to rounding See Financial summaries and Regulation G reconciliations for earnings summary 474M and 454M diluted average number of common shares outstanding for 3Q26 and 3Q25, respectively 1. Excludes offsetting variances from unprotected excess ADIT, affiliate preferred investments, and changes in nuclear decommissioning items and the approved deferrals; see appendix B in the earnings release for more details 2. Other operating expenses include nuclear refueling outage expenses; asset write-offs, impairments, and related charges; decommissioning; taxes other than income taxes; and depreciation and amortization 1.53 0.76 0.11 0.01 1.98 (0.10) (0.05) (0.13) (0.05) (0.09) 3Q25 Utility operating rev. less fuel, purch. power, and reg. chgs. Utility other O&M Utility other operating expenses Utility other income Utility interest expense P&O Income taxes Share effect 3Q26 Entergy adjusted EPS; $ 1 2 1 1
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5 Credit Credit metric outlooks remain better than agency thresholds 1. Senior secured ratings for the operating companies and SERI; corporate credit rating for ETR Credit ratings1 (outlooks) E-AR E-LA E-MS E-NO E-TX SERI ETR Moody’s A2 (stable) A2 (stable) A2 (stable) Baa2 (stable) A3 (stable) Baa2 (stable) Baa2 (stable) S&P A (stable) A (stable) A (stable) BBB (stable) A (stable) BBB+ (stable) BBB+ (stable) Key ETR credit metrics Agency threshold 26E–30E outlook Moody’s CFO pre-working capital to debt >14% ✓ S&P FFO to debt >13% ✓
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6 Rolling forward capital, equity plans to 27E–30E Completed equity needs well into 2028 Investor day 5-year 2026E–2030E equity plan $67B capital plan $7B equity plan Completed / not yet settled Remaining needCompleted / settled Today 4-year 2027E–2030E equity plan $55B capital plan $5.2B equity plan 27E–28E 28E–30E
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7 Adjusted EPS guidance and outlooks Greater than 8% CAGR through 30E1 1. Versus 2025 25 26E guidance 27E outlook 28E outlook 29E outlook 30E outlook Entergy adjusted EPS; $ 3.91 4.35–4.45 4.90–5.20 5.55–5.85 6.25–6.55 7.05–7.35 As-reported 3.91 Narrowed
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8 Looking ahead to the EEI financial conference Topic Update Strategic discussion • Investing for customers, reliability, and resilience • Strong sales growth • Pipeline of potential customers not in base plan supports potential upside opportunities • Other longer-term investment opportunities from accelerated resilience, clean energy, and electrification Preliminary plan and outlooks through 2030 • High level capital plan by operating company • Rate base • High level financing plan • Adjusted earnings per share • Credit 2027 preview • Preliminary drivers for 2027E adjusted EPS growth
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9 Appendix
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10 As of 12/31/25 About Entergy Vertically integrated electric utility with five operating companies in four states – AR, LA, MS, and TX 3.1 million retail customers 24,621 MW owned and leased generating assets 16,128 circuit miles of interconnected high-voltage transmission lines 107,838 circuit miles of distribution lines 2025 Utility weather-adj. retail sales Owned and leased capability as of 12/31/25 Residential Commercial Industrial Governmental CCCT / CT Legacy gas / oil Nuclear Coal Renewables 128 TWh 25 GW
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11 Utility overview Customer counts as of 12/31/25 See Jurisdictional base rate filing frameworks slide and operating company slides for additional details 1. Requested one-year extension for FRP; otherwise, will file a base rate case in 2027 • 738,000 customers • 9.15% – 10.15% authorized ROE • Currently base rate case; E-AR provided notice that it will resume forward test year FRP with 2027 filing • Other investment and cost recovery riders E-AR • 1,115,000 customers • 9.3% – 10.1% authorized ROE • FRP with riders (incl. generation, transmission, and distribution)1 • Other investment and cost recovery riders E-LA • 459,000 customers • 10.14% – 12.14% authorized ROE • FRP with forward- looking features • Other investment and cost recovery riders E-MS • 209,000 customers • 8.85% – 9.85% authorized ROE • FRP with forward- looking features • Other investment and cost recovery riders E-NO • 538,000 customers • 9.57% authorized ROE • Rate case • Other investment and cost recovery riders E-TX
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12 2025 Utility weather-adjusted retail sales 128 TWh Calculations may differ due to rounding E-AR 20% E-LA 48% E-MS 11% E-NO 4% E-TX 17% Residential 28% Commercial 22% Industrial 48% Governmental 2% By operating company By customer class
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13 Utility generation overview Calculations may differ due to rounding Note: the percentage of renewable and nuclear energy includes energy procured or produced for the benefit of certain customers through special tariffs, contracts, or renewable program subscriptions, and those customers retain the exclusive claims to all associated environmental attributes, RECs, and other relevant clean energy certifications 1. Includes generation from both owned and purchased power resources CCCT / CT 38% Legacy gas / oil 8% Nuclear 28% Coal 5% Purchases 18% Renewables 3% 2025 sources of energy 147 TWh CCCT / CT 43% Legacy gas / oil 25% Nuclear 21% Coal 8% Renewables 3% Owned and leased capability as of 12/31/25 25 GW 1
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14 Announced generation projects Project update since last earnings call; OCAPS placed in-service 1. Date of COD or entry of contract 2. Permit denied by the Iberville Parish Council, E-LA requested reconsideration Project MW Owned / PPA Est. in service1 Approved / in progress Greer Solar (E-MS) 170 PPA 2026 Delta Solar (E-MS) 80 Owned 2027 Penton Solar (E-MS) 190 Owned 2028 Bogalusa West Solar (E-LA) 200 Owned 2028 Arkansas Cypress Solar with BESS (E-AR) 600 solar 350 BESS Owned 2028 Cypress Harvest Solar (E-LA)2 200 Owned 2028 Penton BESS (E-MS) 150 Owned 2028 Regulatory review pending Big Island Solar (E-AR) 440 PPA 2028 Segno and Votaw Solar (E-LA) 311 Owned 2029 Bogalusa West, Cypress Harvest, TBD BESS (E-LA) 400 + TBD Owned / TBD TBD Jones Mill, Driver BESS (E-AR) 350 Owned 2028 Project MW Est. in service1 Approved / in progress Delta Blues CCCT (E-MS) 754 2028 Legend CCCT (E-TX) 754 2028 Vicksburg CCCT (E-MS) 754 2028 Lone Star CT (E-TX) 453 2028 Ironwood CT (E-AR) 446 2028 Franklin Farms 1 and 2 CCCTs (E-LA) 1,508 2028 Traceview CCCT (E-MS) 754 2029 Waterford 5 CCCT (E-LA) 754 2029 Jefferson CCCT (E-AR) 754 2029 Regulatory review pending Cottonwood CCCT (E-LA) 1,263 2027 Waterford 6 and Westlake CCCTs (E-LA) 1,508 2030 Richland Parish 1–4, Pointe Coupee 1–3 CCCTs (E-LA) 5,278 2030–31 White Bluff Unit 1 fuel conversion (E-AR) 828 2029 Owned dispatchable generationRenewables + battery storage
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15 Jurisdictional base rate filing frameworks1 See operating company slides for additional details 1. Excludes riders for certain rate base additions outside of base rate filing frameworks 2. Does not include 2025 historical year FRP netting adjustment filing (filed July 2026, see slide 19) 3. May be suspended for an additional nine months 4. Interim rate change up to 2% effective April 1, any rate change above 2% (up to 4% cap) would be placed in rates the month following the receipt of an MPSC order 5. May be suspended for an additional 150 days 6. Required to file base rate case every four years (PUCT may extend if non-material change in rates would result); base rate case also required 18 months after GCRR is utilized for asset(s) totaling more than $200M or if ROE filed in annual earnings monitoring report exceeds the allowed ROE for two consecutive years E-AR E-LA E-MS E-NO E-TX SERI Latest filing date 2/27/26 (rate case)2 6/1/26 (FRP) 2/27/26 (FRP) 4/30/26 (FRP) 7/1/22 (rate case) Monthly cost of service Rate effective date 30 days after filing3 Sept. following filing April following filing4 Sept. following filing 35 days after filing5 Immediate Evaluation period Historical test yr. ended 12/31 plus known and measurable changes through 12/31 of filing yr. Historical test yr. ended 12/31 plus transmission and distribution closed to plant above baseline through 8/31 of filing yr.; rate adjustments permitted for certain generation additions or extraordinary items Historical test yr. ended 12/31 plus certain known and measurable changes through 12/31 of filing yr. Historical test yr. ended 12/31 plus certain known and measurable changes through 12/31 of filing yr. 12-month historical test yr. with available updates Actual current month expense and prior month-end balance sheet FRP term / post FRP framework Will resume forward test yr. FRP following rate case 2026 final filing year in current FRP; requested one-year FRP extension No specified termination; option to file rate case as needed 2027-2030 filing years n/a Monthly cost of service until terminated by mutual agreement Next filing date July 2027 (FRP) TBD March 2027 (FRP) April 2027 (FRP) 20276 (rate case) Every month
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16 Regulatory timeline 1. Interim rate change up to 2% effective April 1, any rate change above 2% (up to 4% cap) would be placed in rates the month following the receipt of an MPSC order Regulatory activities 4Q26 1Q27 2Q27 3Q27 Base rate proceedings E-AR (rate case) E-AR (2025 FRP netting adjustment) E-LA (FRP) TBD E-MS (FRP) Filing 1 E-NO (FRP) Filing Other filings of note E-AR White Bluff Unit 1 fuel conversion E-AR Jones Mill BESS and Driver BESS Filing E-LA RPCR rider Filing Filing E-LA Evest E-LA Cottonwood CCCT acquisition E-LA Waterford 6 and Westlake CCCTs E-LA Segno and Votaw solar Procedural schedule suspended for settlement discussions E-LA Waterford 3 uprate Procedural schedule suspended for settlement discussions E-LA one-year FRP extension E-LA resilience plan phase 1A E-MS Winter Storm Fern securitization E-NO phase 2 resilience / grid hardening TBD E-TX DCRF E-TX TCRF - new rates in effect Illustrative
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17 Entergy Arkansas 1. Five-year initial FRP term and E-AR’s option for five-year renewal 2. Includes $28M for 2024 historical year netting adjustment reserved in 4Q25 E-AR (currently in rates) Metric Details Allowed ROE 9.15% – 10.15% Rate base $11.4B retail rate base (2026 test year) WACC (after-tax) 5.76% Equity ratio 38.0% (47.0% excluding $2.2B ADIT at 0% rate) Regulatory construct Forward test year FRP; result outside ROE band resets to midpoint; maximum rate change 4% of filing year total retail revenue (4% applies to the historical year netting adjustment plus the forward test year projection); rate case required after 10 FRP filings1 Key rate changes in last 12 months $110M Generating Arkansas Jobs Act rider (June 2026), $94M2 FRP (Jan. 2026) Riders Fuel and purchased power, MISO, capacity, Grand Gulf, energy efficiency, Generating Arkansas Jobs Act rider, among others
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18 E-AR base rate case filing Settlement agreement filed Calculations may differ due to rounding See discussion of Rate and Regulatory Matters in the most recent Form 10-K and/or any subsequent Form 10-Qs 1. If higher depreciation rate is approved, the revenue requirement will be accompanied by a corresponding increase in expense Proposed ROE 9.7% Rate base (ADIT incl. in WACC, not rate base) $11.7B WACC (after-tax) 5.75% Equity ratio 38.3% (47.5% excl. $2.2B ADIT at 0% rate) Rate change request - Major drivers of proposed rate change Category $M Cost of capital 6 Rate base 10 Other revenue / sales volume (68) Depr. / higher plant balances 14 Taxes other than income, veg. and other exp. 14 Higher depr. rate1 24 Rate change request - Key dates Filing highlights (docket 26-001-U) Date Event 11/4/26 Hearing begins Dec. 2026 Targeted decision Jan. 2027 Targeted rate effective date
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19 E-AR 2025 historical year FRP netting adjustment Calculations may differ due to rounding See discussion of Rate and Regulatory Matters in the most recent Form 10-K and/or any subsequent Form 10-Qs Filing highlights (docket 16-036-FR) Earned ROE 8.8% Rate base (ADIT incl. in WACC, not rate base) $11.1B WACC (after-tax) 5.57% Equity ratio 37.6% (46.7% excl. $2.1B ADIT at 0% rate) Rate change requested $(9M) Major drivers of proposed rate change Category $M Rate base (10) Base, FRP, and other revenue (19) Depreciation (3) O&M expense 23 Rate change requested (9) Key dates Date Event 11/4/26 Settlement deadline 11/13/26 Hearing begins 12/14/26 Targeted decision Jan. 2027 Targeted rate effective date
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20 E-AR White Bluff Unit 1 fuel conversion See discussion in Management’s Financial Discussion and Analysis - Liquidity and Capital Resources in the most recent Form 10-K and/or any subsequent Form 10-Qs Item Details MW 828 Plant type Natural gas boiler Location Redfield, AR Estimated cost $301M Targeted in-service date June 2029 Proposed recovery Generating Arkansas Jobs Act rider Filing highlights (docket 26-055-U) Key dates Date Event 11/9/26 Settlement deadline 11/19/26 Hearing begins Feb. 2027 Targeted decision
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21 E-AR Jones Mill BESS and Driver BESS See discussion in Management’s Financial Discussion and Analysis - Liquidity and Capital Resources in the most recent Form 10-K and/or any subsequent Form 10-Qs Filing highlights (docket 26-073-U) Item Jones Mill Driver MW 100 250 Location Hot Spring County, AR Mississippi County, AR Estimated cost including associated interconnection facilities $161M $389M Targeted in-service date 2028 2028 Proposed recovery Customer advances for financing costs during construction and FRP once in service Key dates Date Event April 2027 Targeted decision
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22 Entergy Louisiana 1. TRM and DRM each have an annual cap of $400M for 2026 filing year 2. Base FRP has a cumulative cap of $140M for the 2025–2026 filing years, excluding $15M per year for higher nuclear depreciation rates E-LA (currently in rates) Metric Details Allowed ROE 9.3% – 10.1% Rate base $17.0B (12/31/25 test year) + $0.3B TRM, $0.4B DRM, $1.1B RPCR, $0.1B ACM WACC (after-tax) 7.01% Equity ratio 50.83% Regulatory construct FRP: base – historical test year, results below/above ROE band re-set to bottom/top of band; TRM and DRM riders1 – assets in service through 8/31 of filing year using ROE midpoint; generation rider – effective month following in service date using ROE midpoint Key rate changes in last 12 months $15M base FRP2, $34M TRM, $36M DRM, $62M MCRM + ACM + TAM + other; $12M RPCR (Sept. 2026); $20M VMR (May 2026); $52M RPCR (March 2026); $14M ACM + GGO (Feb. 2026) Riders Fuel, ACM, TRM, DRM, TAM, MCRM, RPCR, GGO, VMR among others
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23 E-LA investment to support new Meta agreement Evest; settlement agreement filed Filing request highlights (docket U-37882) • Generation and transmission resources proposed to support load growth including a new data center project in north Louisiana, as follows: • Agreement includes important customer protections, consistent with or better than LPSC guidelines and Fair Share Plus commitment • Electric service agreement provides for subscription up to an additional 2,500 MW of renewable resources under existing E-LA green tariff • Agreement regarding funding of planned and potential nuclear uprates Key dates See discussion in Management’s Financial Discussion and Analysis - Liquidity and Capital Resources in the most recent Form 10-K and/or any subsequent Form 10-Qs Category Investment ($B) 7 CCCTs (>5,200 MW) 12.9 Transmission and related facilities 1.5 BESS 0.7 + TBD Date Event Dec. 2026 Commission decision
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24 E-LA Cottonwood CCCT acquisition See discussion in Management’s Financial Discussion and Analysis - Liquidity and Capital Resources in the most recent Form 10-K and/or any subsequent Form 10-Qs Filing highlights (docket U-37801) Item Details MW 1,263 Plant type 2003 CCCT Location Deweyville, TX Estimated cost ~$1.8B incl. post-acquisition capital repairs and upgrades Targeted acquisition date 1H27 Proposed recovery ACM Key dates Date Event 2/23/27 Hearing begins
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25 E-LA Waterford 6 and Westlake CCCTs See discussion in Management’s Financial Discussion and Analysis - Liquidity and Capital Resources in the most recent Form 10-K and/or any subsequent Form 10-Qs Filing highlights (docket U-37853) Item Waterford 6 Westlake MW 754 754 Plant type CCCT CCCT Location Killona, LA Westlake, LA Estimated cost including transmission interconnection and other related costs $2.0B $2.1B Targeted in-service date 2030 2030 Proposed recovery ACM / FRP or other base recovery mechanism Key dates Date Event Dec. 2026 Requested decision
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26 E-LA Segno and Votaw solar Procedural schedule suspended for settlement discussions Item Segno Solar Votaw Solar MW 170 141 Plant type Solar photovoltaic Solar photovoltaic Location Polk County, TX Hardin County, TX Targeted in-service date 2029 2029 Proposed recovery Combination of ACM and customer subscription revenue See discussion in Management’s Financial Discussion and Analysis - Liquidity and Capital Resources in the most recent Form 10-K and/or subsequent Form 10-Qs Filing highlights (docket U-37800)
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27 E-LA Waterford 3 nuclear uprate Procedural schedule suspended for settlement discussions Filing highlights (docket U-37677) • Uprate project and cost recovery • Total estimated cost ~$69M • Project details: Phase I Phase II Expected capacity 40 MW 5 MW Projected in-service date Nov. 2026 Dec. 2029 Proposed recovery ACM FRP or other base recovery mechanism
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28 E-LA one-year FRP extension request Key dates Date Event By 12/31/26 Targeted decision Filing highlights (docket U-36959) • Request to extend the existing FRP for one year (2027 filing year) • Same terms as existing FRP, no midpoint reset See discussion in Rate and Regulatory Matters in the most recent Form 10-K and/or any subsequent Form 10-Qs Key terms unchanged Allowed ROE 9.3% – 10.1% Base FRP cap $140M TRM/DRM caps $400M each
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29 E-LA resilience plan phase 1A Key dates Filing highlights (docket U-38082) • Incremental $600M investment over a four-year period (2027–2030) • Proposed recovery through existing RPCR rider with semi-annual updates Date Event 1/22/27 Staff/intervenor direct 3/25/27 E-LA rebuttal 6/28/27 Hearing begins 7/31/27 Targeted decision
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30 Entergy Mississippi 1. Excludes the portion of rate changes related to capacity costs E-MS (currently in rates) Metric Details Allowed ROE 11.14% performance-adjusted midpoint (10.75% + 0.39% performance factor); 10.14% – 12.14% range (reset annually based on formula) Rate base $4.9B (2026 forward test year) WACC (after-tax) 7.68% Equity ratio 49.72% Regulatory construct FRP with forward-looking features; performance-based bandwidth (results outside WACC band reset to midpoint); maximum rate increase 4% of test year retail revenue (increase above 4% requires base rate case); subject to annual look-back evaluation Key rate changes in last 12 months1 $2M FRP interim facilities rate true-up (April 2026), $15M PMR (Feb. 2026), $65M FRP interim facilities rate (Jan. 2026) Riders Fuel, Grand Gulf, MISO, storm damage mitigation and restoration, ad valorem tax adjustment, grid modernization, PMR, FRP interim facilities rate adjustment, among others
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31 E-MS Winter Storm Fern securitization Key dates Filing highlights (docket 26-UA-85) • Requests financing order for securitization of $238M Date Event 12/1/26 Expected decision Category $M Storm damages 218 Carrying and financing costs 20 Total 238
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32 Entergy New Orleans 1. Includes $1.6M of items that do not impact earnings and $1.2M realigned from the RSCHR rider E-NO (currently in rates) Metric Details Allowed ROE 8.85% – 9.85% (9.35% midpoint) Rate base $1.2B (12/31/25 test year plus known and measurables through 12/31/26) + $0.1B RSHCR WACC (after-tax) 7.45% Equity ratio 55% Regulatory construct FRP with forward-looking features; result outside ROE band resets to midpoint Key rate changes in last 12 months $16M1 FRP (Sept. 2026), $12M RSHCR rider (Jan. 2026) Riders Fuel and purchased power, MISO, energy efficiency, environmental, capacity costs, RSHCR, among others
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33 E-NO phase 2 resilience and grid hardening See discussion in Management’s Financial Discussion and Analysis - Liquidity and Capital Resources in the most recent Form 10-K and/or subsequent Form 10-Qs Filing highlights (docket UD 21-03) • Five-year (2027–2031) phase 2 plan • $400M investment • Proposed recovery via RSHCR rider Key dates TBD
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34 Entergy Texas 1. Required to file base rate case every four years (PUCT may extend if non-material change in rates would result); base rate case also required 18 months after GCRR is utilized for asset(s) totaling more than $200M or if ROE filed in annual earnings monitoring report exceeds the allowed ROE for two consecutive years 2. One TCRF may be filed each calendar year that includes changes to net plant since the last base rate case or TCRF test period 3. Two DCRFs may be effective each calendar year that include changes to net plant since the last base rate case or DCRF test period 4. GCRR available for owned or acquired generating facilities; no limit to the number of filings between rate cases (cumulative investment of more than $200M requires base rate case filing within 18 months) E-TX (currently in rates) Metric Details Allowed ROE 9.57% Rate base $4.4B (12/31/21 test year) +$1.2B GCRR (thru 12/25), $1.0B DCRF (thru 12/25), $0.4B TCRF (thru 6/25) WACC (after-tax) 6.61% Equity ratio 51.2% Regulatory construct Historical test year rate case1; interim rate base riders: TCRF2, DCRF3, and GCRR4 Key rate changes in last 12 months $145M GCRR (Oct. 2026), $20M DCRF (July 2026), $21M TCRF (April 2026), $14M DCRF (Dec. 2025) Riders Fuel, capacity, DCRF, TCRF, GCRR, CCRR among others
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35 E-TX DCRF Filing highlights (docket 60292) • Additional $111M net distribution investment since the end of the last DCRF test period (12/31/25) through 6/30/26 • $15M incremental revenue requirement • ROE, WACC, and equity ratio from most recent rate case See discussion in Rate and Regulatory Matters in the most recent Form 10-K and/or subsequent Form 10-Qs Key dates Date Event 4Q26 Targeted decision
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36 E-TX TCRF Key dates Filing highlights (docket 60409) • Additional $239M net transmission investment since the end of the last TCRF test period (6/30/25) through 6/30/26 • $26M incremental revenue requirement • 10% ROE, 7.15% WACC, and 50.12% equity ratio Date Event 2Q27 Targeted decision See discussion in Rate and Regulatory Matters in the most recent Form 10-K and/or subsequent Form 10-Qs
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37 System Energy Resources Calculations may differ due to rounding SERI (most recent monthly bill) Metric Detail Principal asset Ownership and leasehold interest in GGNS Authorized ROE 9.65% Last calculated rate base $2.0B WACC (after-tax) 7.71% Equity ratio 50.1% Regulatory construct Monthly cost of service E-AR, 24 E-MS, 56 E-NO, 19 Energy and capacity allocation; % Grand Gulf Nuclear Station
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38 Financial disclosures
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39 Adjusted EPS progress against guidance Guidance range narrowed to $4.35 – $4.45; YTD 3Q26 $3.89 1. Includes refueling outage amortization; asset write-offs, impairment, and related charges; decommissioning expense; taxes other than income taxes; and depreciation expense 2. Excludes YoY variance from change in affiliate preferred interest and change in returns on NDTs and the approved deferrals (both largely earnings neutral) Select drivers YTD 3Q26 YoY variance ($/share) 4Q comments Weather-adjusted retail sales volume and other revenue 0.54 Expect ~0.05–0.10 QoQ Utility other O&M (0.18) Expect ~(0.10)–(0.15) QoQ (includes flex spending) Utility other operating expenses 1 (0.17) Expect ~(0.15) QoQ Utility other income and interest expense 2 (0.08) Expect ~0.05 QoQ P&O excl. income tax rate, share effect, and affiliate preferred 2 (0.13) Expect ~(0.05) QoQ Effective income tax rate (consolidated) 0.03 Expect ~(0.00)–(0.05) QoQ Share effect (0.18) Expect ~(0.00)–(0.05) QoQ
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40 Select financing activity 3Q26 Entity Activity Date Rate Amount ($M) Maturity Notes Entergy Corp. Issuance 8/7 6.50%1 6.50%1 750 750 12/15/56 12/15/58 Junior subordinated debentures E-LA Issuance 8/13 5.50% 500 9/15/36 6.20% 500 9/15/56 Entergy Corp. Retirement 9/1 2.95% 750 n/a E-TX Retirement 9/1 1.50% 130 n/a Entergy Corp. Equity forward settlements 9/2 n/a 9132 n/a ~11M shares 1. Initial interest rate; subject to reset 2. Net proceeds 4Q26 Entity Activity Date Rate Amount ($M) Maturity Notes E-LA Retirement 10/1 2.40% 400 n/a
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41 Financial summaries and Regulation G reconciliations
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42 Earnings summary Calculations may differ due to rounding See Appendix A in the earnings release for additional details 1. 474M and 454M diluted average common shares outstanding for 3Q26 and 3Q25, respectively Table 1: Third quarter earnings summary $ in millions Per share in $1 3Q26 3Q25 3Q26 3Q25 As-reported (after-tax) Utility 1,079 810 2.28 1.79 Parent & Other (139) (117) (0.29) (0.26) Consolidated 940 694 1.98 1.53 Less adjustments Utility - - - - Parent & Other - - - - Consolidated - - - - Adjusted (non-GAAP) Utility 1,079 810 2.28 1.79 Parent & Other (139) (117) (0.29) (0.26) Consolidated 940 694 1.98 1.53
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43 Regulation G reconciliations Calculations may differ due to rounding Table 2: ETR adjusted earnings Reconciliation of GAAP to non-GAAP measures 3Q26 3Q25 (Pre-tax except for income taxes and totals; $ in millions) Net income (loss) attributable to ETR Corp. 940 694 Less adjustments - - ETR adjusted earnings (non-GAAP) 940 694 Diluted average number of common shares outstanding (in millions) 474 454 (After-tax, per share in $) Net income (loss) attributable to ETR Corp. 1.98 1.53 Less adjustments - - ETR adjusted earnings (non-GAAP) 1.98 1.53
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44 Regulation G reconciliations Calculations may differ due to rounding Table 3: ETR adjusted earnings Reconciliation of GAAP to non-GAAP measures 2025 (Pre-tax except for income taxes and totals; $ in millions) Net income (loss) attributable to ETR Corp. 1,758 Less adjustments - ETR adjusted earnings (non-GAAP) 1,758 Diluted average number of common shares outstanding (in millions) 450 (After-tax, per share in $) Net income (loss) attributable to ETR Corp. 3.91 Less adjustments - ETR adjusted earnings (non-GAAP) 3.91
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45 Utility book ROEs Calculations may differ due to rounding 1. Utility does not equal the sum of the operating companies primarily due to SERI (as-reported and adjusted earnings ~$91M, and average common equity ~$976M) and Entergy Utility Holding Co. Table 4: Utility book ROE summary LTM ending Sept. 30, 2026 ($ in millions) E-AR E-LA E-MS E-NO E-TX Utility1 As-reported earnings available to common stock (a) 491 1,238 393 61 397 2,626 Less adjustments: Total adjustments (b) - - - - - - Adjusted earnings available to common stock (non-GAAP) (c) = (a) - (b) 491 1,238 393 61 397 2,626 Average common equity (d) 5,080 12,406 3,116 639 4,073 26,086 Adjustment for E-LA affiliate preferred (offset at P&O) Preferred investment, net of noncontrolling interest (beginning / ending average) (e) 3,887 Estimated equity financing for preferred investment (beginning / ending average) (f) 2,872 Dividend income from affiliate preferred, net of noncontrolling interest (g) 279 Estimated debt financing for preferred investment (h) 1,014 Average cost of debt (after-tax) (i) 3.18% Cost of debt financing for preferred investment (after-tax) (j) = - (h) x (i) (32) As-reported ROE (a) / (d) 9.7% 10.0% 12.6% 9.5% 9.8% 10.1% Adjusted ROE (non-GAAP) (c) / (d) 9.7% 10.0% 12.6% 9.5% 9.8% 10.1% Adjusted ROE, excluding average affiliate preferred (non-GAAP) (c-g-j) / (d-f) 10.4%
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ETR