Slides
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0 Third quarter 2025 earnings call October 29, 2025
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1 Caution regarding forward-looking statements and Regulation G compliance In this presentation, and from time to time, Entergy Corporation makes certain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, among other things, statements regarding Entergy’s 2025 earnings guidance; financial and operational outlooks; industrial load growth outlooks; statements regarding its resilience plans, goals, beliefs, or expectations; and other statements of Entergy’s plans, beliefs, or expectations included in 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. Except to the extent required by the federal securities laws, 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, any subsequent Quarterly Reports on Form 10-Q, and Entergy’s other reports and filings made under the Securities Exchange Act of 1934; (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 by the utilities 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 risk that any such transaction may not be completed as and when expected and the risk that the anticipated benefits of the transaction may not be realized, and (2) Entergy’s ability to meet the rapidly growing demand for electricity, including from hyperscale data centers and other large customers, and to manage the impacts of such growth on customers and Entergy’s business, or the risk that contracted or expected load growth does not materialize or is not sustained; (h) 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 (i) effects on Entergy or its customers of (1) changes in federal, state, or local laws and regulations and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, international trade, or energy policies; (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.
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2 Section Slides Business discussion 3–8 Appendix About Entergy 10 Utility 11–29 Financial disclosures 30–32 Financial summaries and Regulation G reconciliations 33–37 Table of contents
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3 Highlights See Financial summaries and Regulation G reconciliations section for earnings summary Key messages – Productive quarter with strong adjusted EPS and continued progress on customer growth, operational initiatives, and regulatory outcomes – Strong cash flow and credit metrics – Narrowed adjusted EPS guidance and outlooks and extended outlook period to 2029; continue to expect greater than 8% CAGR – Increased data center pipeline to 7 GW to 12 GW – Secured an additional 4.5 GW of power island equipment, available for large growth opportunities – Long-term strategy and plans to be discussed at EEI financial conference 3Q25 adjusted EPS $1.53 3Q25 OCF $2.1B
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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 454M and 431M diluted average number of common shares outstanding for 3Q25 and 3Q24, respectively (Entergy executed a two-for-one forward stock split that was effective with trading on Dec.13, 2024; 2024 share and per-share information reflects the post-split share count) 1. Excludes offsetting variances from unprotected excess ADIT, the effect of HLBV accounting and the approved deferral, affiliate preferred investments, and changes in nuclear decommissioning items; see appendix B in the earnings release for more details 2. Other operating expenses include nuclear refueling outage expenses; asset write-offs, impairment, and related charges; decommissioning, taxes other than income taxes; and depreciation and amortization 1.50 0.26 0.08 0.05 0.01 1.53 (0.09) (0.12) (0.07) (0.08) 3Q24 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 3Q25 Entergy adjusted EPS; $ 1 1 2 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 25E–29E outlook Moody’s CFO pre-working capital to debt >14% ✓ S&P FFO to debt >13% ✓
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6 Rolling forward capital and equity plans to 26E–29E 2025E–2028E 4-year plan Completed Remaining need 2026E–2029E 4-year plan $40B capital plan $4.7B equity plan $41B capital plan $4.4B equity plan
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7 Adjusted EPS guidance and outlooks Greater than 8% CAGR1 through 29E 1. 2029E vs 2024 compound annual growth rate 24 25E guidance 26E outlook 27E outlook 28E outlook 29E outlook Entergy adjusted EPS; $ 3.65 3.85–3.95 4.25–4.45 4.70–5.00 5.20–5.50 As-reported 2.45 Narrowed 5.75–6.05 Added
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8 Looking ahead to the EEI financial conference Topic Update Strategic discussion • Investing for growth, reliability, and resilience • Strong customer growth with industrial pipeline that supports potential upside opportunities • Longer-term opportunities from clean energy transition and electrification Preliminary plan and outlooks through 2029 • Capital plan • Rate base • Financing plan • Adjusted earnings per share • Credit 2026 preview • Preliminary drivers for 2026E adjusted EPS growth
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9 Appendix
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10 As of 12/31/24 About Entergy Vertically integrated electric utility with five operating companies in four states – AR, LA, MS, and TX 3 million retail customers 24,479 MW owned and leased generating assets 16,100 circuit miles of interconnected high-voltage transmission lines 107,255 circuit miles of distribution lines 2024 Utility weather-adj. retail sales Owned and leased capability as of 12/31/24 Residential Commercial Industrial Governmental CCCT / CT Legacy gas / oil Nuclear Coal Renewables 123 TWh 24 GW
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11 Utility overview Customer counts as of 12/31/24 See Jurisdictional base rate filing frameworks slide and operating company slides for additional details • 735,000 customers • Authorized ROE: 9.15% – 10.15% • Forward test year FRP E-AR • 1,110,000 customers • Authorized ROE: 9.3% – 10.1% • FRP with riders (incl. generation, transmission, and distribution) E-LA • 459,000 customers • Authorized ROE: 10.25% – 12.26% • FRP with forward- looking features E-MS • 209,000 customers • Authorized ROE: 8.85% – 9.85% • FRP with forward- looking features E-NO • 524,000 customers • Authorized ROE: 9.57% • Rate case and cost recovery riders (transmission, distribution, and generation) E-TX
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12 Utility 2024 weather-adjusted retail sales 123 TWh Calculations may differ due to rounding E-AR 19% E-LA 49% E-MS 10% E-NO 5% E-TX 17% Residential 29% Commercial 23% Industrial 46% 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 42% Legacy gas 10% Nuclear 27% Coal 3% Purchases 16% Renewables 2% 2024 sources of energy 142 TWh CT / CCCT 43% Legacy gas / oil 25% Nuclear 21% Coal 8% Renewables 3% Owned and leased capability as of 12/31/24 24 GW 1
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14 Announced generation projects Details on RFPs are available at rfp.entergy.com 1. Date of COD or entry of contract Project MW Owned / PPA Est. in service1 Approved / in progress Forgeview Solar (E-AR) 200 PPA 2025 Sterlington Solar (E-LA) 49 Owned 2026 Mondu Solar (E-LA) 100 PPA 2026 Wildwood Solar (E-MS) 100 PPA 2026 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 Regulatory review pending Cypress Solar with BESS (E-AR) 600 solar 350 BESS Owned 2028 Project MW Est. in service1 Approved / in progress OCAPS CCCT (E-TX) 1,215 2026 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 CCCT (E-LA) 754 2028 Franklin Farms 2 CCCT (E-LA) 754 2028 Traceview CCCT (E-MS) 754 2029 Waterford 5 CCCT (E-LA) 754 2029 Regulatory review pending Jefferson CCCT (E-AR) 754 2029 Owned dispatchable generationRenewables + 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. 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 3. May be suspended for an additional 150 days 4. 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 7/7/25 (FRP) 5/30/25 (FRP) 2/28/25 (FRP) 4/30/25 (FRP) 7/1/22 (rate case) Monthly cost of service Rate effective date Jan. following filing Sept. following filing April following filing2 Sept. following filing 35 days after filing3 Immediate Evaluation period Forward test yr. ended 12/31 and historical test year true-up 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 Five yrs. (2021–2025 filing yrs.); rate case after FRP expiration Three yrs. (2024−2026 filing yrs.); could request extension and/or file a rate case after FRP expiration No specified termination; option to file rate case as needed Three yrs. (2024– 2026 filing yrs.); could request extension and/or file a rate case after FRP expiration n/a Monthly cost of service until terminated by mutual agreement Next filing date Feb. 2026 (rate case) May 2026 (FRP) March 2026 (FRP) April 2026 (FRP) 20274 (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 MPSC order Regulatory activities 4Q25 1Q26 2Q26 3Q26 Base rate proceedings E-AR FRP Rate case filing E-LA (FRP) Filing E-MS (FRP) Filing 1 E-NO (FRP) Filing Other key filings E-AR Jefferson Power Station E-AR Cypress Solar with BESS E-LA West Bank 500 kV E-LA Waterford 3 uprate E-TX Cypress to Legend 500 kV E-TX DCRF - new rates in effect Illustrative
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17 Entergy Arkansas 1. Includes $15.5M for 2023 historical year netting adjustment reserved in 4Q24 E-AR (currently in rates) Metric Detail Authorized ROE 9.15% – 10.15% Rate base $11.3B retail rate base (2025 test year) WACC (after-tax) 5.58% Equity ratio 37.9% (47.0% excluding $2.0B ADIT at 0% rate) Regulatory construct Forward test year FRP; result outside ROE band reset to midpoint; maximum rate change 4% of filing year total retail revenue (4% applies to the historical year true-up plus the forward test year projection) Key rate changes in last 12 months $83M1 FRP (Jan. 2025) 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 annual FRP filing 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 2024 test year 2026 test year Earned ROE 7.71% 8.45% Rate base (ADIT incl. in WACC, not rate base) $10.3B $11.4B WACC (after-tax) 5.67% 5.79% Equity ratio 38.6% (47.0% excluding $2.0B ADIT at 0% rate) 38.0% (47.0% excluding $2.2B ADIT at 0% rate) Revenue requirements to midpoint $49M $69M Rate change requested $92M (cap) Major drivers of proposed rate change ($M) Category 2024 test year 2026 test year Cost of capital 4 24 Expense items (12) 59 Rate base 11 12 Other revenue / sales volume 46 (26) Total revenue requirement 49 69 Rate change requested 92 (cap) Key dates (proposed) Date Event 10/29/25 Settlement deadline 11/6/25 Hearing begins 12/12/25 APSC decision 1/2/26 Rate effective date Filing highlights (docket 16-036-FR)
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19 E-AR Jefferson Power Station filing 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 25-047-U) Item Details MW 754 Plant Type CCCT Location Jefferson County, AR Targeted in-service date Dec. 2029 Proposed recovery Generating Arkansas Jobs Act rider Key dates Date Event 10/30/25 Hearing 1/28/26 Expected decision deadline
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20 E-AR Cypress Solar with BESS filing 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 Key dates Date Event 11/5/25 Staff and intervenor surrebuttal 11/12/25 E-AR sur-surrebuttal 11/21/25 Settlement or issues list 12/1/25 Hearing 3/4/26 Expected decision deadline Filing highlights (docket 25-054-U) • A 600 MW solar photovoltaic array with a 350 MW battery energy storage system and associated transmission facilities • Targeted in-service date Dec. 2028 • Proposed recovery through Generating Arkansas Jobs Act rider
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21 Entergy Louisiana 1. TRM and DRM each have an annual cap of $350M for 2024 filing year, increasing $25M/year in subsequent years (excluding $153M Hurricane Francine capital in DRM); investments not included in riders will be included in base FRP 2. Includes $15M for higher nuclear depreciation rates 3. Credited to customers over two months (Sept. and Oct. 2025 bills) E-LA (currently in rates) Metric Detail – electric Authorized ROE 9.3% – 10.1% Rate base $16.7B (12/31/24 test year) + $0.2B TRM, $0.4B DRM, $0.4B RPCR WACC (after-tax) 6.95% Equity ratio 50.91% 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 $15M2 base FRP, $18M TRM, $42M DRM, $(84M) MISO + ACM + TAM + other (largely offset in other line items), $10M RPCR (Sept. 2025); one-time customer credit $(32M) (Sept–Oct. 2025)3 ; $40M RPCR, $18M DRM (March 2025) Riders Fuel, capacity, TRM, DRM, TAM, MCRM, ACM, RPCR, among others
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22 E-LA West Bank 500 kV transmission filing Filing highlights (docket U-37467) • A portfolio of Amite South transmission projects located on the West Bank of the Mississippi River, including construction of a new 84-mile 500 kV line • Total estimated cost ~$955M • Proposed recovery through TRM, if active; otherwise requesting regulatory asset until in rates • Projected major in-service dates: Waterford 500 kV substation expansion 3Q27 Churchill 500 kV substation 4Q27 Construction of tie lines to 500 kV substation 1Q28 Commodore-Churchill 500 kV line 1Q28 Conversion of the Waterford-Churchill 230 kV line to 500 kV 3Q28 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 Key dates Date Event 1Q26 Targeted decision
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23 E-LA Waterford 3 nuclear uprate filing Filing highlights (docket U-37677) • Uprate project and cost recovery • Total estimated cost ~$69M • Project details: Key dates 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 Date Event 2/13/26 Staff/intervenor direct 5/8/26 E-LA rebuttal deadline 6/29/26 Hearing begins 3Q26 Targeted decision
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24 Entergy Mississippi E-MS (currently in rates) Metric Detail Authorized ROE 11.25% performance-adjusted midpoint (10.90% + 0.35% performance factor); 10.25% – 12.26% range (reset annually based on formula) Rate base $4.6B (2025 forward test year) WACC (after-tax) 7.69% Equity ratio 49.83% 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 months $4M grid modernization rider (largely offset in other O&M) (Feb. 2025), $47M FRP interim facilities rate adjustment (Jan. 2025), $9M FRP interim facilities rate adjustment (July–Dec. 2024) 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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25 Entergy New Orleans E-NO (currently in rates) Metric Detail Authorized ROE 8.85% – 9.85% (9.35% midpoint) Rate base $1.2B (12/31/24 test year plus known and measurables through 12/31/25) WACC (after-tax) 7.35% Equity ratio 55% Regulatory construct FRP with forward-looking features; result outside ROE band resets to midpoint Key rate changes in last 12 months $(7M) FRP (Sept. 2025), $1M RSHCR rider (Jan. 2025) Riders Fuel and purchased power, MISO, energy efficiency, environmental, capacity costs, RSHCR
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26 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 Detail Authorized ROE 9.57% Rate base $4.4B (12/31/21 test year) + $0.7B DCRF (through 12/24), $0.1B TCRF (through 6/24) 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 $29M DCRF (June 2025), $10M TCRF (Apr. 2025), $8M DCRF (Dec. 2024), $40M DCRF (Oct. 2024) Riders Fuel, capacity, DCRF, TCRF, GCRR, among others
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27 E-TX Cypress to Legend 500 kV filing Filing highlights (docket 58136) • 500 kV transmission line (~40–49 line miles) • Total estimated cost ~$0.4B • Proposed recovery through TCRF rider • Projected in service date Dec. 2028 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 Key dates Date Event 4Q25 Targeted decision
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28 E-TX DCRF filing Key dates Filing highlights (docket 58745) • Additional $169M net distribution investment since the end of the last DCRF test period 1/1/25 through 6/30/25 • $17M incremental revenue requirement • ROE, WACC, and equity ratio from most recent rate case Date Event 4Q25 Targeted decision Dec. 2025 Rate effective date See discussion in Rate and Regulatory Matters in the most recent Form 10-K and/or subsequent Form 10-Qs
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29 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 $1.81B WACC (after-tax) 7.83% Equity ratio 50.7% 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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30 Financial disclosures
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31 25E adjusted EPS progress Guidance range narrowed to $3.85 – $3.95; YTD $3.40 1. All values in $/share except where noted 2. Includes nuclear refueling outage expenses, decommissioning, taxes other than income taxes, and depreciation and amortization 3. Excludes YoY variance from change in affiliate preferred interest (largely earnings neutral) and change in returns on NDTs (offset by regulatory deferrals) 4. Excludes effects from unprotected excess ADIT (offset in Utility earnings revenue) Select drivers YTD 3Q25 YoY variance1 4Q comments Estimated weather in sales 0.20 Weather-adj. retail sales volume 0.33 Expect ~flat QoQ Utility other O&M and other operating expenses 2 (0.28) Expect ~(0.20) QoQ (includes flex spending) Utility other income 3 0.27 Expect ~0.05–0.10 QoQ Utility interest expense (0.23) Expect ~(0.05) QoQ P&O excl. income tax rate, share effect, and affiliate preferred 3 0.03 Expect ~flat QoQ Income taxes 4 0.02 Expect ~(0.05) QoQ (YTD ~23%) Share effect (0.14) Expect minimal impact QoQ (YTD ~447M diluted shares, settled $332M / 5.7M shares equity forwards on 10/10/25)
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32 2025 adjusted EPS sensitivities As of Feb. 2025 1. Excludes potential fluctuations in demand charges; residential impact lower than previous years due to rate design changes (e.g., increased fixed charge and decreased volumetric charge); actual contribution can vary due to differences in operating company mix Variable Description of sensitivity Estimated annual EPS impact (+/-) Utility Retail sales volume incremental to plan1 1% change in residential MWh sold 1% change in commercial MWh sold 1% change in industrial MWh sold ~0.03 ~0.015 ~0.01 Other O&M 1% change in expense ~0.05 Rate base $100 million change in rate base in rates ~0.01 ROE 25 basis point change in allowed ROE ~0.13 Entergy consolidated Interest expense 1% change in interest rate on $1 billion debt ~0.02 Effective tax rate 1% change in effective tax rate ~0.05
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33 Financial summaries and Regulation G reconciliations
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34 Earnings summary Calculations may differ due to rounding See Appendix A in the earnings release for additional details 1. 454M and 431M diluted average common shares outstanding for 3Q25 and 3Q24, respectively (Entergy executed a two-for-one forward stock split that was effective with trading on Dec. 13, 2024; 2024 share and per-share information reflects the post-split share count) Table 1: Third quarter earnings summary $ in millions Per share in $1 3Q25 3Q24 3Q25 3Q24 As-reported (after-tax) Utility 810 787 1.79 1.82 Parent & Other (117) (142) (0.26) (0.33) Consolidated 694 645 1.53 1.50 Less adjustments Utility - - - - Parent & Other - - - - Consolidated - - - - Adjusted (non-GAAP) Utility 810 787 1.79 1.82 Parent & Other (117) (142) (0.26) (0.33) Consolidated 694 645 1.53 1.50
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35 Regulation G reconciliations Calculations may differ due to rounding Note: Entergy executed a two-for-one forward stock split that was effective with trading on Dec. 13, 2024; 2024 share and per-share information reflects the post-split share count Table 2: ETR adjusted earnings Reconciliation of GAAP to non-GAAP measures 3Q25 3Q24 (Pre-tax except for income taxes and totals; $ in millions) Net income (loss) attributable to ETR Corp. 694 645 Less adjustments: - - ETR adjusted earnings (non-GAAP) 694 645 Diluted average number of common shares outstanding (in millions) 454 431 (After-tax, per share in $) Net income (loss) attributable to ETR Corp. 1.53 1.50 Less adjustments: - - ETR adjusted earnings (non-GAAP) 1.53 1.50
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36 Regulation G reconciliations Calculations may differ due to rounding Note: Entergy executed a two-for-one forward stock split that was effective with trading on Dec. 13, 2024; 2024 share and per-share information reflects the post-split share count Table 3: ETR adjusted earnings Reconciliation of GAAP to non-GAAP measures 2024 (Pre-tax except for income taxes and totals; $ in millions) Net income (loss) attributable to ETR Corp. 1,056 Less adjustments: Utility - 4Q24 E-LA adjustment to a regulatory liability primarily related to securitization resulting from Louisiana state income tax rate change 9 Utility - 2Q24 E-LA global agreement to resolve its FRP extension filing and other retail matters (151) Utility - 1Q24 E-AR write-off of a regulatory asset related to the opportunity sales proceeding (132) Utility - 1Q24 E-NO increase in customer sharing of income tax benefits as a result of the 2016–2018 IRS audit resolution (79) Utility - income tax effect on adjustments above 92 Utility - 4Q24 income tax expense resulting from Louisiana state income tax rate change (29) P&O - 2024 pension lift out (320) P&O - DOE spent nuclear fuel litigation settlements 25 P&O - income tax effect on adjustments above 62 ETR adjusted earnings (non-GAAP) 1,577 Diluted average number of common shares outstanding (in millions) 432 (After-tax, per share in $) Net income (loss) attributable to ETR Corp. 2.45 Less adjustments: Utility - 4Q24 Louisiana state income tax rate change, including an adjustment to E-LA’s associated regulatory liability (0.05) Utility - 2Q24 E-LA global agreement to resolve its FRP extension filing and other retail matters (0.26) Utility - 1Q24 E-AR write-off of a regulatory asset related to the opportunity sales proceeding (0.23) Utility - 1Q24 E-NO increase in customer sharing of income tax benefits as a result of the 2016–2018 IRS audit resolution (0.13) P&O - 2024 pension lift out (0.59) P&O - DOE spent nuclear fuel litigation settlements 0.05 ETR adjusted earnings (non-GAAP) 3.65
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37 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 ~$87M, and average common equity ~$1,039M) and Entergy Utility Holding Co. Table 4: Utility book ROE summary LTM ending September 30, 2025 ($ in millions) E-AR E-LA E-MS E-NO E-TX Utility1 As-reported earnings available to common stock (a) 453 1,121 309 55 325 2,303 Less adjustments: 4Q24 Louisiana state income tax rate change, including an adjustment to E-LA’s associated regulatory liability (9) (0) (22) Total adjustments (b) - (9) - (0) - (22) Adjusted earnings available to common stock (non-GAAP) (c) = (a) - (b) 453 1,131 309 56 325 2,325 Average common equity (d) 4,758 11,710 2,534 713 3,451 24,083 Adjustment for E-LA affiliate preferred (offset at P&O) Preferred investment, net of noncontrolling interest (beginning / ending average) (e) 4,136 Estimated equity financing for preferred investment (beginning / ending average) (f) 3,122 Dividend income from affiliate preferred, net of noncontrolling interest (g) 297 Estimated debt financing for preferred investment (h) 1,015 Average cost of debt (after-tax) (i) 3.08% Cost of debt financing for preferred investment (after-tax) (j) = (h) x (i) 31 As-reported ROE (a) / (d) 9.5% 9.6% 12.2% 7.8% 9.4% 9.6% Adjusted ROE (non-GAAP) (c) / (d) 9.5% 9.7% 12.2% 7.8% 9.4% 9.7% Adjusted ROE, excluding average affiliate preferred (non-GAAP) (c-g-j) / (d-f) 10.1%
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ETR