Slides
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0 Fourth quarter 2025 earnings call Feb. 12, 2026
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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 2026 adjusted earnings per share 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 3–9 Appendix About Entergy 11 Utility 12–34 Financial disclosures 35–44 Financial summaries and Regulation G reconciliations 45–48 Table of contents
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3 Highlights See Financial summaries and Regulation G reconciliations section for earnings summary Key messages – 2025 was another successful year • Adjusted EPS in top half of guidance range • Strong cash flow and credit metrics • Secured additional long-term growth to benefit stakeholders – Outlooks remain strong • Greater than 8 percent adjusted EPS CAGR through 2029 • $43 billion customer-centric capital plan • Strong credit metric outlook, comfortably above rating agencies’ thresholds 2025 adjusted EPS $3.91 2025 OCF $5.2B
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4 2025 adjusted earnings per share Calculations may differ due to rounding See Financial summaries and Regulation G reconciliations for earnings summary 450M and 432M diluted average number of common shares outstanding for 2025 and 2024, respectively 1. Excludes offsetting variances from unprotected excess ADIT, the effect of HLBV accounting, affiliate preferred investments, and changes in nuclear decommissioning items and the approved deferral; 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 3.65 0.93 0.29 0.03 3.91 (0.28) (0.20) (0.32) (0.01) (0.17) 24 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 25 Entergy adjusted EPS; $ 1 1 2 1
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5 Forecast highlights Strong sales growth outlook, $43B capital plan, equity needs unchanged Calculations may differ due to rounding 1. 2029E vs 2025 2. Excludes capital funded with contribution in aid of construction from customers Cumulative weather-adj. retail sales growth vs 2025; TWh 7 16 33 48 26E 27E 28E 29E Residential Commercial Industrial ~8% retail sales CAGR1 ~15% industrial CAGR1 2026E–2029E capital plan by function2 8 9 6 15 4 1 $43B Distribution Transmission Renewables and storage New generation Generation baseline Other Completed / not yet settled Remaining need 2026E–2029E 4-year equity plan $4.4B Completed / settled
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6 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–29E outlook Moody’s CFO pre-working capital to debt >14% ✓ S&P FFO to debt >13% ✓
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7 Adjusted EPS guidance and outlooks Greater than 8% CAGR1 through 29E 1. 2029E vs 2025 25 26E guidance 27E outlook 28E outlook 29E outlook Entergy adjusted EPS; $ 3.91 4.25–4.45 4.70–5.00 5.20–5.50 As-reported 3.91 5.75–6.05
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8 2026 adjusted EPS drivers 1. Excludes offsetting variances from unprotected excess ADIT and changes in nuclear decommissioning items and the approved deferral 2. Other operating expenses include nuclear refueling outage expense; asset write-offs, impairment, and related charges; decommissioning; taxes other than income taxes; and depreciation and amortization 3. Excludes variances from affiliate interest on preferred investments (~$(0.02) at Utility and ~$0.02 at P&O, largely earnings neutral) 3.91 4.25 – 4.45 25 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 Inc. tax rate and share effect 26E guidance Entergy adjusted EPS; $ As-reported 3.91 2 1,3 Illustrative 3 1
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9 Save the date Investor day June 9, 2026 New York City
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10 Appendix
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11 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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12 Utility overview Customer counts as of 12/31/25 See Jurisdictional base rate filing frameworks slide and operating company slides for additional details • 738,000 customers • Authorized ROE: 9.15% – 10.15% • Forward test year FRP • Other investment recovery riders E-AR • 1,115,000 customers • Authorized ROE: 9.3% – 10.1% • FRP with riders (incl. generation, transmission, and distribution) • Other investment recovery riders E-LA • 459,000 customers • Authorized ROE: 10.25% – 12.26% • FRP with forward- looking features • Other investment recovery riders E-MS • 209,000 customers • Authorized ROE: 8.85% – 9.85% • FRP with forward- looking features • Other investment recovery riders E-NO • 538,000 customers • Authorized ROE: 9.57% • Rate case • Other investment recovery riders E-TX
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13 Utility 2025 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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14 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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15 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 Mondu Solar (E-LA) 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 Arkansas Cypress Solar with BESS (E-AR) 600 solar 350 BESS Owned 2028 Segno Solar (E-LA) 170 Owned 2029 Votaw Solar (E-LA) 141 Owned 2029 Big Island Solar (E-AR) 440 PPA 2028 Cypress Harvest Solar (E-LA) 200 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 Jefferson CCCT (E-AR) 754 2029 Regulatory review pending Cottonwood CCCT (E-LA) 1,263 2027 Waterford 6 CCCT (E-LA) 754 2030 Westlake CCCT (E-LA) 754 2030 Owned dispatchable generationRenewables + storage
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16 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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17 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 1Q26 2Q26 3Q26 4Q26 Base rate proceedings E-AR Rate case filing E-LA (FRP) Filing E-MS (FRP) Filing 1 E-NO (FRP) Filing Other key filings E-AR AR Cypress Solar w/ BESS E-LA Cottonwood acquisition E-LA Segno and Votaw Solar E-LA Waterford 6 CCCT Procedural schedule TBD E-LA Westlake CCCT Procedural schedule TBD E-LA Babel - Webre 500kV Procedural schedule TBD E-LA Cypress Harvest Solar E-LA Waterford 3 uprate E-LA resilience rider Filing Filing E-NO phase 2 resilience Procedural schedule TBD E-TX TCRF - new rates in effect Illustrative
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18 Entergy Arkansas 1. Includes $28M for 2024 historical year netting adjustment reserved in 4Q25 E-AR (currently in rates) Metric Detail Authorized 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 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); rate case required at least after 10 FRP filings Key rate changes in last 12 months $94M1 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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19 E-AR Arkansas 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-Q Filing highlights (docket 25-054-U) Item Details MW 600 350 Plant type Solar photovoltaic Battery energy storage system Location Pastoria, AR Estimated cost $1.6B including transmission interconnection and other related costs Targeted in-service date Dec. 2028 Proposed recovery Generating Arkansas Jobs Act rider Key dates Date Event 3/4/26 Expected decision
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20 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 $14M GGO + ACM (Feb. 2026); $15M base FRP2, $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, ACM, TRM, DRM, TAM, MCRM, RPCR, GGO, among others
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21 E-LA resilience plan cost recovery rider Semi-annual filing Key dates Filing highlights (docket U-36625) • $391M rate base from new assets in service through Aug. 2026 • $52M incremental revenue requirement • ROE, WACC, and equity ratio from most recent FRP Date Event March 2026 Rate effective date
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22 E-LA Cottonwood CCCT acquisition 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 U-37801) Item Details MW 1,263 Plant type 2003 CCCT Location Deweyville, TX Estimated cost ~$1.8B including post-acquisition capital repairs and plant upgrades Targeted acquisition date Jan. 2027 Proposed recovery ACM Key dates Date Event 6/5/26 Staff/intervenor direct 7/24/26 E-LA rebuttal 9/9/26 Hearing begins Oct. 2026 Targeted decision
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23 E-LA Waterford 6 CCCT 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 TBD) Item Details MW 754 Plant type CCCT Location Killona, LA Estimated cost $2B including transmission interconnection and other related costs Targeted in-service date 2030 Proposed recovery ACM / FRP or other base recovery mechanism Key dates Procedural schedule TBD
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24 E-LA Westlake CCCT 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 TBD) Item Details MW 754 Plant type CCCT Location Westlake, LA Estimated cost $2.1B including transmission interconnection and other related costs Targeted in-service date 2030 Proposed recovery ACM / FRP or other base recovery mechanism Key dates Procedural schedule TBD
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25 E-LA Segno and Votaw solar filing Item Segno Solar Votaw Solar MW 170 141 Plant type Solar photovoltaic Location Polk County, TX Hardin County, TX Targeted in-service date 2029 Proposed recovery ACM + 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) Key dates Date Event 5/1/26 Staff/intervenor direct 6/4/26 E-LA rebuttal 7/7/26 Hearing begins Aug. 2026 Targeted decision
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26 E-LA Cypress Harvest Solar 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 U-36697) Item Details MW 200 Plant Type Solar photovoltaic Location Iberville Parish, Louisiana Targeted in-service date 2028 Proposed recovery GGO rider Key dates Date Event April 2026 Targeted decision
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27 E-LA Babel to Webre 500kV transmission filing Filing highlights (docket U-37812) • Seeks certification of the construction of a 147-mile 500kV transmission line, expansion of an existing 500kV switching station, and construction of a new 500kV switching station • Total estimated cost ~$1.2B • Proposed recovery through TRM, if active; otherwise requesting regulatory asset until in rates • Projected major in-service dates: 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 Construction of tie lines to 500kV substation 4Q28 Babel 500kV switching station expansion 1Q29 Webre 500kV switching station 3Q29 Babel to Webre 500kV line 3Q29 Date Event 2Q26 Targeted decision
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28 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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29 Entergy Mississippi 1. Excludes the portion of rate changes related to capacity costs 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 months1 $15M PMR (Feb. 2026), $65M FRP interim facilities rate (Jan. 2026), $4M grid modernization rider (largely offset in other O&M) (Feb. 2025) 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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30 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) + $0.1B RSHCR 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 $12M RSHCR rider (Jan. 2026), $(7M) FRP (Sept. 2025) Riders Fuel and purchased power, MISO, energy efficiency, environmental, capacity costs, RSHCR, among others
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31 E-NO phase 2 resilience and grid hardening filing 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 Procedural schedule TBD Filing highlights (docket UD 21-03) • Five-year (2027–2031) phase 2 plan • $400M investment • Proposed recovery via Resilience and Storm Hardening Cost Recovery Rider
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32 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) + $0.8B DCRF (through 6/25), $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 $14M DCRF (Dec. 2025), $29M DCRF (June 2025), $10M TCRF (April 2025) Riders Fuel, capacity, DCRF, TCRF, GCRR, among others
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33 E-TX TCRF filing Key dates Filing highlights (docket 58889) • Additional $240M net distribution investment since the end of the last TCRF test period (6/30/24 through 6/30/25) • $21M incremental revenue requirement • ROE, WACC, and equity ratio from most recent rate case Date Event 2/20/26 PUCT open meeting 3/12/26 PUCT open meeting 1Q26 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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34 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 $1.79B WACC (after-tax) 7.81% Equity ratio 50.8% 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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35 Financial disclosures
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36 Key guidance drivers 2026 adjusted EPS guidance range $4.25 – $4.45 1. Includes refueling outage amortization asset write-offs, impairment, and related charges , decommissioning expense, taxes other than income taxes, and depreciation expense 2. Excludes YoY variance from change in returns on NDTs (offset by regulatory deferrals) 3. Excludes YoY variance from change in affiliate preferred interest (expected to be ~$(0.02) Utility and $0.02 P&O) Driver Assumption (in EPS, except where noted) Utility Regulatory proceedings Full year of 2025 rate actions and planned 2026 rate actions See Adjusted EPS – quarterly considerations slides and individual OpCo slides Weather $(0.20) YoY change (normal weather in 26E) Weather-adjusted retail volume and other revenue ~$0.45 – $0.50 YoY change • Weather-adj. retail sales growth ~5%, driven by ~10% industrial growth • Increase in customer advances for return on CWIP for certain utility projects Other O&M ~$0.20 – $0.25 YoY change (driven partly by flex spending in 2025) Other operating expenses 1 ~$(0.35) – $(0.40) YoY change • Driven by depr. exp. and taxes other than income taxes (primarily higher plant in service) Other income 2,3 and interest exp. ~$(0.05) – $(0.10) YoY change • Higher interest exp. (higher debt balances, higher average interest rates) • Partially offset by net effects of tax gross ups and carrying charges on customer advances Gas LDC sale Effective 7/1/25; reduces revenue, operating expenses, and interest expense P&O excl. income tax rate, share effect, and affiliate preferred interest3 ~$(0.20) YoY change (primarily higher interest expense) Effective inc. tax rate (consolidated) Essentially flat YoY (~23% effective income tax rate) Share effect (consolidated) ~$(0.15) – $(0.20) YoY change (~468M fully diluted average shares)
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37 Adjusted EPS – quarterly considerations Calculations may differ due to rounding 1. Annualized pre-tax expense, recovered by FRP rate change 2025 items of note (EPS, unless otherwise noted) 1Q 2Q 3Q 4Q ETR as-reported EPS 0.82 1.05 1.53 0.51 Adjustments - - - - ETR adjusted EPS 0.82 1.05 1.53 0.51 Diluted average number of common shares outstanding (in millions) 441 446 454 459 2025 timing considerations Estimated effect of weather 0.05 0.08 0.06 0.01 Weather-adjusted retail sales (% of total) 23% 25% 29% 23% 4Q25 E-AR 2024 historical year netting adjustment (reg. charges) 0.05 E-TX MISO summer PRA capacity costs (0.04) (0.02) E-MS PPA termination (Misc. revenue) 0.02 (0.01) Various write offs (other O&M) (0.03) (0.02) Natural gas LDC businesses (sold 7/1/25) Final sale (asset impairment) (0.02) Final sale (other O&M) 0.02 Revenue before sale 0.07 0.05 E-LA nuclear depr. rate $15M1 2025 flex spending (other O&M) Largely 4Q Income tax adj. from expiration of certain tax carryforwards (P&O) (0.04)
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38 Adjusted EPS – quarterly considerations(continued) 2025 items of note (continued) 1Q 2Q 3Q 4Q 2025 key rate actions (annualized pre-tax rate change) E-MS grid mod rider1 (Feb.) $4M E-LA RPCR (March) $40M E-LA DRM (March) $18M E-TX TCRF (April) $10M E-TX DCRF (June) $29M E-LA FRP, TRM, DRM, and other1 (Sept.) $(9)M E-LA RPCR (Sept.) $10M E-LA one-time customer credit (Sept.–Oct.) $(32)M E-NO FRP (Sept.) $(7M) E-TX DCRF (Dec.) $14M 2026 items of note 1Q 2Q 3Q 4Q 2026 timing considerations E-LA nuclear depr. rate $15M2 AFUDC OCAPS planned in service summer 2026 Utility other income YoY change weighted to 4Q26 P&O YoY change weighted to 2H 1. Largely offset in other line items 2. Annualized pre-tax expense, recovered by FRP rate change
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39 Adjusted EPS – quarterly considerations(continued) 2026 items of note (continued) 1Q 2Q 3Q 4Q 2026 key rate actions (annualized pre-tax rate change) E-AR FRP (Jan.) $94M1 E-NO RSHCR (Jan.) $12M E-MS FRP interim facilities rate (Jan.) $65M E-LA GGO rider + ACM (Feb.) $14M E-MS PMR rate adj. (Feb.)2 $15M E-LA RPCR (March) $52M E-TX TCRF (March) TBD E-MS FRP (April) 2 TBD E-AR Generating Arkansas Jobs Act rider (2Q26) TBD E-TX GCRR (Summer) (OCAPS in service) TBD E-LA FRP with riders (Sept.) TBD E-LA RPCR (Sept.) TBD E-NO FRP (Sept.) TBD E-TX TCRF and/or DCRF TBD (timing and amounts) 1. Includes $28M for 2024 historical year netting adjustment reserved in 4Q25 2. Excludes the portion of rate changes related to capacity costs 3. 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
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40 Four-year capital plan by OpCo1 1. Excludes capital funded with contribution in aid of construction from customers E-AR 26E 27E 28E 29E Total Distribution 310 310 380 400 1,400 Transmission 85 140 175 215 615 Generation Renewables and storage 430 805 475 5 1,715 Other new generation 820 790 460 95 2,165 Nuclear 155 145 220 260 780 Other non-nuc. gen. 105 130 85 195 515 Total generation 1,510 1,870 1,240 555 5,175 Utility support 65 55 65 50 235 Total 1,970 2,375 1,860 1,220 7,425 Depreciation expense 480 490 515 595 2,080 E-LA 26E 27E 28E 29E Total Distribution 1,165 830 560 605 3,160 Transmission 1,670 1,675 1,315 885 5,545 Generation Renewables and storage 360 660 1,350 1,085 3,455 Other new generation 1,645 3,290 1,350 1,770 8,055 Nuclear 240 290 210 340 1,080 Other non-nuc. gen. 305 250 145 105 805 Total generation 2,550 4,490 3,055 3,300 13,395 Utility support 90 85 70 70 315 Total 5,475 7,080 5,000 4,860 22,415 Depreciation expense 865 980 1,075 1,285 4,205 E-MS Distribution 370 345 325 350 1,390 Transmission 230 160 140 110 640 Generation Renewables and storage 325 200 60 - 585 Other new generation 1,090 1,005 280 65 2,440 Nuclear - - - - - Other non-nuc. gen. 45 35 75 55 210 Total generation 1,460 1,240 415 120 3,235 Utility support 45 65 45 35 190 Total 2,105 1,810 925 615 5,455 Depreciation expense 280 295 340 395 1,310 E-NO Distribution 185 125 110 150 570 Transmission 10 15 15 30 70 Generation Renewables and storage 15 - - - 15 Other new generation - - - - - Nuclear - - - - - Other non-nuc. gen. - 10 50 20 80 Total generation 15 10 50 20 95 Utility support 15 10 10 15 50 Total 225 160 185 215 785 Depreciation expense 80 85 90 95 350 $M
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41 Four-year capital plan by OpCo1 (continued) 1. Excludes capital funded with contribution in aid of construction from customers E-TX 26E 27E 28E 29E Total Distribution 525 445 335 340 1,645 Transmission 385 615 680 645 2,325 Generation Renewables and storage 5 - 5 5 15 Other new generation 595 200 1,325 - 2,120 Nuclear - - - - - Other non-nuc. gen. 85 85 105 75 350 Total generation 685 285 1,435 80 2,485 Utility support 35 30 45 35 145 Total 1,630 1,375 2,495 1,100 6,600 Depreciation expense 355 375 415 425 1,570 SERI 26E 27E 28E 29E Total Distribution - - - - - Transmission - - - - - Generation Renewables and storage - - - - - Other new generation - - - - - Nuclear 130 115 135 140 520 Other non-nuc. gen. - - - - - Total generation 130 115 135 140 520 Utility support 25 5 5 25 60 Total 155 120 140 165 580 Depreciation expense 130 135 135 140 540 Entergy Services, LLC Distribution - - - - - Transmission - - - - - Generation Renewables and storage - - - - - Other new generation - - - - - Nuclear - - - - - Other non-nuc. gen. - - - - - Total generation - - - - - Utility support 55 45 50 60 210 Total 55 45 50 60 210 Depreciation expense 40 40 40 40 160 Total Utility Distribution 2,555 2,055 1,710 1,845 8,165 Transmission 2,380 2,605 2,325 1,885 9,195 Generation Renewables and storage 1,135 1,665 1,890 1,095 5,785 Other new generation 4,150 5,285 3,415 1,930 14,780 Nuclear 525 550 565 740 2,380 Other non-nuc. gen. 540 510 460 450 1,960 Total generation 6,350 8,010 6,330 4,215 24,905 Utility support 330 295 290 290 1,205 Total 11,615 12,965 10,655 8,235 43,470 Depreciation expense 2,230 2,400 2,610 2,975 10,215 $M
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42 Financing activity 1. Includes actual activity through 2/11/26 and debt 1Q26 debt maturities 2. Original maturity date 4/1/26 4Q25 Entity Activity Date Rate Amount ($M) Maturity Notes Entergy Corp. Issuance 11/7/25 5.875% 600 6/15/56 Use of proceeds includes repayment of debt outstanding and general corporate purposes 6.1% 700 1Q261 Entity Activity Date Rate Amount ($M) Maturity Notes E-AR Issuance 1/8/26 4.95% 500 1/15/36 Use of proceeds includes repayment of debt, financing generation construction, and general corporate purposes 5.75% 500 1/15/56 E-LA Retirement 1/15/26 4.44% 250 n/a Entergy Corp. Equity forward settlements 2/2/26 n/a 346 n/a 4.6 millions shares settled E-AR Retirement 2/9/262 3.5% 600 n/a
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43 Financing plan Calculations may differ due to rounding 1. Subject to change 2. Issued 1/8/26 3. Excludes revolvers, commercial paper, sale/leaseback bonds, nuclear fuel, and securitized debt 4. Redeemed 2/9/26 Debt maturity schedule as of 12/31/253; $M Company 26E 27E 28E 29E E-AR 6004 - 350 - E-LA 650 450 425 - E-MS - 150 375 - E-NO 85 - - 35 E-TX 130 150 - 300 SERI - - 325 - Total Utility 1,465 750 1,475 335 ETR Corp. 750 - 650 - Total 2,215 750 2,125 335 Company 26E 27E 28E 29E Utility long-term debt; $M E-AR 1,0002 800 700 300 E-LA 2,750 3,420 2,320 1,650 E-MS 500 700 800 - E-NO 80 - 70 100 E-TX 500 430 1,236 115 SERI - - 335 - Wtd. avg. rate assumption ~6% Parent debt rate assumptions ~6% – ~7% Issuances1
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44 2026 adjusted EPS sensitivities As of Feb. 2026 1. Excludes potential fluctuations in demand charges; 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 $500 million change in rate base in rates ~0.04 ROE 25 basis point change in allowed ROE ~0.15 Entergy consolidated Interest expense 1% change in interest rate on $1 billion debt ~0.02 Effective tax rate 1% change in effective tax rate ~0.06
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45 Financial summaries and Regulation G reconciliations
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46 Earnings summary Calculations may differ due to rounding See Appendix A in the earnings release for additional details 1. 450M and 432M diluted average common shares outstanding for 2025 and 2024, respectively Table 1: Full year earnings summary $ in millions Per share in $1 2025 2024 2025 2024 As-reported (after-tax) Utility 2,280 1,827 5.06 4.23 Parent & Other (521) (771) (1.16) (1.79) Consolidated 1,758 1,056 3.91 2.45 Less adjustments Utility - (289) - (0.67) Parent & Other - (233) - (0.54) Consolidated - (522) - (1.21) Adjusted (non-GAAP) Utility 2,280 2,115 5.06 4.90 Parent & Other (521) (538) (1.16) (1.25) Consolidated 1,758 1,577 3.91 3.65
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47 Regulation G reconciliations Calculations may differ due to rounding Table 2: ETR adjusted earnings Reconciliation of GAAP to non-GAAP measures 2025 2024 (Pre-tax except for income taxes and totals; $ in millions) Net income (loss) attributable to ETR Corp. 1,758 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 agreement in principle 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 - 4Q24 DOE spent nuclear fuel litigation settlements - 25 P&O - income tax effect on adjustments above - 62 ETR adjusted earnings (non-GAAP) 1,758 1,577 Diluted average number of common shares outstanding (in millions) 450 432 (After-tax, per share in $) Net income (loss) attributable to ETR Corp. 3.91 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 agreement in principle 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 - 4Q24 DOE spent nuclear fuel litigation settlements - 0.05 ETR adjusted earnings (non-GAAP) 3.91 3.65
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48 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 ~$88M, and average common equity ~$966M) and Entergy Utility Holding Co. Table 3: Utility book ROE summary LTM ending December 31, 2025 ($ in millions) E-AR E-LA E-MS E-NO E-TX Utility1 As-reported earnings available to common stock (a) 441 1,110 312 50 332 2,280 Less adjustments: Total adjustments (b) - - - - - - Adjusted earnings available to common stock (non-GAAP) (c) = (a) - (b) 441 1,110 312 50 332 2,280 Average common equity (d) 4,574 11,724 2,689 653 3,581 24,042 Adjustment for E-LA affiliate preferred (offset at P&O) Preferred investment, net of noncontrolling interest (beginning / ending average) (e) 4,091 Estimated equity financing for preferred investment (beginning / ending average) (f) 3,076 Dividend income from affiliate preferred, net of noncontrolling interest (g) 292 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) 9.6% 9.5% 11.6% 7.7% 9.3% 9.5% Adjusted ROE (non-GAAP) (c) / (d) 9.6% 9.5% 11.6% 7.7% 9.3% 9.5% Adjusted ROE, excluding average affiliate preferred (non-GAAP) (c-g-j) / (d-f) 9.8%
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ETR