Slides
Page 1
0 Second quarter 2025 earnings call July 30, 2025
Page 2
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 climate transition and 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.
Page 3
2 Section Slides Business discussion 3–10 Appendix About Entergy 12 Utility 13–35 Financial disclosures 36–44 Financial summaries and Regulation G reconciliations 45–49 Table of contents
Page 4
3 Highlights See Financial summaries and Regulation G reconciliations section for earnings summary Key messages – Very strong 2Q25 retail sales growth, including ~12% industrial growth – Strong sales outlook, including significant new load in Arkansas plus a strong pipeline of customer interest – Continuing progress on resilience including capital investment, regulatory/legislative enactments, and financial readiness – Settled ~$800 million of equity forwards in May; equity needs into 2027 contracted – Updating capital plan to serve growing customer needs – Affirming 2025 adjusted EPS guidance and updating 27E–28E outlooks 2Q25 adjusted EPS $1.05 2Q25 OCF $1,262M
Page 5
4 Updating capital plan, raising 27E–28E outlooks Four-year industrial sales CAGR ~13% Note: Entergy executed a two-for-one forward stock split that was effective with trading on December 13, 2024; all per-share information reflects the post-split share count 1. For adjusted EPS, 4Q24 reference is guidance and outlook midpoints 25E–27E settlement 27E–28E settlement Equity needs; $B Remaining need 40 25E 26E 27E 28E 4-year capital plan; cumulative $B 4Q24 call1 24 25E 26E 27E 28E Adjusted EPS; $ Unchanged Completed Settled 3 0.05 0.10
Page 6
5 2Q adjusted earnings per share Calculations may differ due to rounding See Financial summaries and Regulation G reconciliations for earnings summary 446M and 429M diluted average number of common shares outstanding for 2Q25 and 2Q24, respectively (Entergy executed a two-for-one forward stock split that was effective with trading on December 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, decommissioning, taxes other than income taxes, and depreciation and amortization 0.96 0.17 0.10 0.01 1.05 (0.05) (0.04) (0.06) (0.04) 2Q24 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 Share effect 2Q25 Entergy adjusted EPS; $ 1 1 2 1
Page 7
6 Credit Credit metric outlooks remain better than agency thresholds 1. Senior secured ratings for the OpCos 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–28E outlook Moody’s CFO pre-working capital to debt >14% ✓ Standard & Poor’s FFO to debt >13% ✓
Page 8
7 Nuclear PTCs 1. Nuclear PTC annual amounts subject to inflation adjustments 2. Includes capacity and energy revenue 0 100 200 300 400 500 600 700 20 25 30 35 40 45 50 Nuclear PTC ($M)1 Gross receipts from nuclear production ($/MWh)2 Nuclear PTC benefits; Illustration based on 39–43 TWh annual nuclear production Illustrative Estimated value of 2024 PTCs 2024 estimated PTC ~$570M • Accounted for as an uncertain tax position until clarity from U.S. Treasury on proper calculation method • Assuming cash benefit in 2025 outlook; conservatively not including potential benefit in out years’ forecast • Once OpCos receive cash benefit, may reduce rate base after uncertain tax position is resolved and until cash benefit flows to customers • Goal is to smooth out volatility for customers
Page 9
8 Investing for customer benefits Adding $3B to our four-year capital plan Calculations may differ due to rounding 1. Excludes capital funded with contribution in aid of construction from customers 25E–28E capital plan by function1 8 8 7 12 4 1 Distribution Transmission Renewables and storage Other new generation Generation baseline Other $40B
Page 10
9 1. As of 6/30/25; does not reflect adjustments, including for common dividends between contracting and settlement; shares were sold into the market by the forward counterparties; Entergy expects to physically settle the forwards Equity plan unchanged Strong cash flows help fund higher capital needs 0.8 1.6 1.5 0.8 Settlement in 25E–26E, into 27E Settlement in 27E–28E Equity needs; $B Sufficient market capacity to satisfy with ATM Completed1 Remaining need Settled / cash rec'd. 25E–26E contracted27E contracted 27E–28E to be contracted Equity cash inflow by year Illustrative ATM forwards not yet settled 1Q25 forward offering not yet settled Settled / cash rec’d.
Page 11
10 Raising 27E–28E adjusted EPS outlooks Greater than 8% CAGR1 through 28E 1. From 2024 adjusted EPS 24 25E guidance 26E outlook 27E outlook 28E outlook Entergy adjusted EPS; $ 3.65 3.75–3.95 4.25–4.45 4.70–5.00 5.20–5.50 As-reported 2.45 0.05 0.10
Page 12
11 Appendix
Page 13
12 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
Page 14
13 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
Page 15
14 Utility 2024 weather-adjusted retail sales 123 TWh 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
Page 16
15 Utility generation overview 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
Page 17
16 New generation to meet growing demand Announced projects Details on RFPs are available at rfp.entergy.com Note: Timing and/or cost of certain projects may be impacted by supply chain issues 1. Date of COD or entry of contract 2. All owned CCCTs will be constructed for future CCS and hydrogen capability 3. All owned CTs will be constructed for future hydrogen capability 4. Regulatory proceeding currently in abatement to allow for continued settlement discussions 5. Procedural schedule suspended in October 2024 to evaluate developments affecting project cost Project MW Owned / PPA Est. in service1 Flat Fork Solar (E-AR) 200 PPA 2025 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 OCAPS CCCT (E-TX)2 1,215 Owned 2026 Delta Solar (E-MS) 80 Owned 2027 Penton Solar (E-MS) 190 Owned 2028 Delta Blues CCCT (E-MS)2 754 Owned 2028 Lake Catherine Unit 5 CT (E-AR)3 446 Owned 2028 CCCT (E-MS)2 754 Owned 2029 Approved / in progress Project MW Owned / PPA Est. in service1 ETR OpCo filings Segno Solar (E-TX)4 170 Owned 2027 Votaw Solar (E-TX)4 141 Owned 2028 Franklin Farms 1 CCCT (E-LA)2 754 Owned 2028 Franklin Farms 2 CCCT (E-LA)2 754 Owned 2028 Bayou Power Station (E-LA)5 112 Owned 2028 Legend CCCT (E-TX)2 754 Owned 2028 Lone Star CT (E-TX)3 453 Owned 2028 Waterford 5 CCCT (E-LA)2 754 Owned 2029 Upcoming filings Jefferson CCCT (E-AR)2 754 Owned 2029 Regulatory reviews pending
Page 18
17 Jurisdictional base rate filing frameworks See operating company slides for additional details 1. Excludes riders for certain additions outside of annual FRPs 2. In addition to base rate case filings, E-TX can file for interim recovery through DCRF, TCRF, and GCRR riders 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 4. May be suspended for an additional 150 days 5. 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-LA1 E-MS E-NO1 E-TX2 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 filing3 Sept. following filing 35 days after filing4 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) 20275 (rate case) Every month
Page 19
18 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 3Q25 4Q25 1Q26 2Q26 Base rate proceedings E-AR FRP filing Rate case filing E-LA (FRP) Filing E-MS (FRP) Filing 1 E-NO (FRP) Filing Other key filings E-LA invest. for new customer E-LA West Bank 500 kV CCN E-LA resilience rider Filing Filing E-LA Waterford 3 uprate Procedural schedule TBD E-TX dispatchable gen. CCN E-TX renewable CCN Currently in abatement to allow for continued settlement discussions E-TX SETEX 500 kV CCN E-TX Cypress 500 kV CCN - new rates in effect
Page 20
19 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
Page 21
20 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 10/16/25 E-AR rebuttal 10/31/25 Settlement deadline 11/5/25 Hearing begins 12/12/25 APSC decision 1/2/26 Rate effective date Filing highlights (docket 16-036-FR)
Page 22
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. Blackbox settlement of $120M plus $15M for higher nuclear depreciation rates E-LA (currently in rates) Metric Detail – electric Authorized ROE 9.3% – 10.1% Rate base $16.4B (12/31/23 test year) + $0.1B TRM, $0.4B DRM, $(0.4B) TAM, $0.3B RPCR WACC (after-tax) 6.95% Equity ratio 50.81% 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 $40M RPCR, $18M DRM (March 2025), $135M2 base FRP, $14M TRM, $46M DRM, $12M MCRM (offset in other line items), $(8M) TAM (offset in other line items) (Sept. 2024) Riders Fuel, capacity, TRM, DRM, TAM, MCRM, ACM, RPCR
Page 23
22 E-LA annual FRP filing Annual FRP (docket U-37594) Filing highlights Earned ROE 9.98% Allowed ROE 9.3% – 10.1% (9.7% midpoint) Rate base $16.7B plus $0.4B for transmission and distribution plant closings through 8/31/25 WACC (after-tax) 6.95% Equity ratio 50.91% Major drivers of proposed rate change Category $M Base FRP1 15 TRM 21 DRM 38 MISO, ACM and other2 (22) TAM2 (62) Total FRP (10) One-time customer credit3 (32) Key dates Date Event 8/20/25 Staff and parties to identify issues with the filing deadline Sept. 2025 Rate effective date Calculations may differ due to rounding See discussion in Rate and Regulatory Matters in the most recent Form 10-K and/or any subsequent Form 10-Qs 1. Includes $15M for higher nuclear depreciation rates 2. Largely earnings neutral due to offsets in other line items 3. Per the FRP settlement, for TY 2024 only, the 2024 revenue requirement above 9.7% will be credited to customers in September and October 2025 bills
Page 24
23 E-LA investment to support new customer 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 request highlights (docket U-37425) • Generation and transmission resources proposed in connection with service to a new hyperscale data center in north Louisiana, including: – three new CCCTs totaling 2,262 MW, each of which will be enabled for future CCS – a new 500 kV transmission line and 500 kV substation upgrades • Implementation of a corporate sustainability rider, contemplating customer funding substantial costs associated with the future addition of 1,500 MW of solar and energy storage resources, agreements involving CCS at E-LA’s LCPS, and potential future wind and nuclear resources • Status: settlement with Staff and other parties Key dates Date Event 10/22/25 LPSC B&E meeting (expected decision no later than)
Page 25
24 E-LA West Bank 500 kV transmission CCN filing Filing request 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 8/18/25 Hearing begins 4Q25 Targeted decision
Page 26
25 E-LA resilience plan cost recovery rider Semi-annual filing Key dates Filing highlights (docket U-36625) • $84M rate base from new assets in service through September 2025 • $10M incremental revenue requirement • ROE, WACC, and equity ratio from most recent FRP Date Event Sept. 2025 Rate effective date
Page 27
26 E-LA Waterford 3 nuclear uprate filing Filing request highlights (docket U-37677) • Seeks approval for uprate project and cost recovery • Total estimated cost $69M • Project details: Key dates Procedural schedule TBD 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
Page 28
27 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 interim facilities rider (Jan.–Dec. 2025), $43M vegetation / storm reserve rider (offset in other O&M) (July 2024), $9M interim facilities rider (July–Dec. 2024) Riders Fuel, Grand Gulf, MISO, unit power cost, storm damage mitigation and restoration, ad valorem tax adjustment, grid modernization, restructuring credit, PMR, interim facilities, interim capacity
Page 29
28 Entergy New Orleans E-NO (currently in rates) Metric Detail Authorized ROE 8.85% – 9.85% (9.35% midpoint) Rate base $1.3B (12/31/23 test year plus known and measurables through 12/31/24) WACC (after-tax) 7.28% Equity ratio 55% Regulatory construct FRP with forward-looking features; result outside ROE band resets to midpoint Key rate changes in last 12 months $1M RSHCR rider (Jan. 2025), $5.8M FRP (Sept. 2024) Riders Fuel and purchased power, MISO, energy efficiency, environmental, capacity costs, RSHCR
Page 30
29 E-NO annual FRP filing Calculations may differ due to rounding See discussion in Rate and Regulatory Matters in the most recent Form 10-K and/or any subsequent Form 10-Qs 1. Includes amortization of regulatory liabilities from agreed upon customer refunds 2. Other items include $1M for recovery of a reliability regulatory asset and $4M for late fee reduction (offset by lower late fee revenue) Annual FRP (docket UD-18-07) Filing highlights Earned ROE 10.98% Allowed ROE 8.85% – 9.85% (9.35% midpoint) Rate base $1.2B WACC (after-tax) 7.35% Equity ratio 55% Revenue excess to midpoint excl. realignment from riders $(6M) Realignment from riders1 $(8M) Other items2 $5M Total FRP revenue request $(9M) Key dates Major drivers of proposed rate change Date Event 8/19/25 Review proposed corrections deadline Sept. 2025 Rate effective date Category $M Income taxes (4) Investment in plant (3) O&M and A&G expenses (3) Regulatory debits/credits (2) Decrease in base revenues 6 Realignment from riders1 (8) Other items2 5 Total revenue request (9)
Page 31
30 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, rate case expenses, and AMS surcharge, among others
Page 32
31 E-TX dispatchable generation CCN filing Item Legend Power Station Lone Star Power Station MW 754 453 Est. total investment $1.6B $0.8B Plant type CCCT with H2 capability and CCS-enabled CT with H2 capability Location Jefferson County, TX San Jacinto County, TX In-service date 2028 2028 Recovery mechanism GCRR GCRR 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 request highlights (docket 56693) Key dates Date Event 3Q25 Targeted decision
Page 33
32 E-TX renewable CCN filing Currently in abatement to allow for continued settlement discussions Item Segno Solar Votaw Solar MW 170 141 Plant type Solar photovoltaic Solar photovoltaic Location Polk County, TX Hardin County, TX In-service date 2027 2028 Recovery mechanism GCRR GCRR 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 request highlights (docket 56865) Key dates TBD
Page 34
33 E-TX SETEX 500 kV transmission CCN filing Filing request highlights (docket 57648) • 500 kV transmission line and two stations and associated 138/230 kV facilities − ~131–160 line miles − Babel 500 kV switching station and Running Bear substation • Total estimated cost ~$1.3B – $1.5B • Recovery through TCRF rider • Projected in service date Dec. 2029 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 8/31/25 Targeted decision
Page 35
34 E-TX Cypress to Legend 500 kV CCN filing Filing request highlights (docket 58136) • 500 kV transmission line (~40–49 line miles) • Total estimated cost ~$0.4B • 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 7/21/25 Intervenor direct testimony 8/1/25 Staff direct testimony 8/8/25 E-TX rebuttal testimony 8/18/25 – 8/19/25 Hearing on the merits 4Q25 Targeted decision
Page 36
35 System Energy Resources 1. Including MSS-4 replacement tariff resales SERI (most recent monthly bill) Metric Detail Principal asset Ownership and leasehold interest in GGNS Authorized ROE 9.65% Last calculated rate base $1.83B WACC (after-tax) 7.22% Equity ratio 45.5% Regulatory construct Monthly cost of service E-AR 24% E-MS 56% E-NO 20% Energy and capacity allocation1 Grand Gulf Nuclear Station
Page 37
36 Financial disclosures
Page 38
37 Progress against guidance 1. All values in $/share except where noted 2. Includes refueling outage expenses, 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 Driver Guidance assumption1 YTD result1 Full-year comments ETR adjusted EPS 3.75–3.95 1.87 Estimated weather in sales Normal 0.14 Weather-adj. retail sales volume ~0.25 0.16 Now expect ~0.25 YoY Utility other O&M ~0.15 (0.02) Now expect ~flat YoY • 3Q25 estimate ~(0.05) vs. 3Q24 Utility other operating expenses 2 ~(0.35) (0.07) Now expect ~(0.20) YoY Utility other income 3 ~0.25 0.19 Utility interest expense ~(0.25) (0.16) Now expect ~(0.25) YoY P&O excl. income tax rate, share effect, and affiliate preferred 3 Slight decline (0.02) Now expect ~flat YoY Income taxes 4 ~(0.15) 0.01 Expect ~flat YoY Share effect (0.07) Expect ~(0.15) Effective income tax rate 4 ~24% ~23% Fully diluted average shares ~446M ~443M Now expect ~448M Other considerations E-TX MISO PRA capacity expense n/a (0.04) Expect ~(0.10) YoY , ~(0.06) in 3Q LDC sale / revenue n/a - Expect (0.08) in 2H25, more weighted to 4Q (offset by changes in expenses)
Page 39
38 2025 ETR adjusted EPS sensitivities As of February 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 $1 billion debt ~0.02 Effective tax rate 1% change in effective tax rate ~0.05
Page 40
39 Debt financing activity 2Q25 debt financing activity OpCo Activity Date Rate Amount ($M) Maturity Notes E-AR Issuance 5/8/25 5.45% 300 6/1/34 Use of proceeds includes construction of Lake Catherine Unit 5 and general corporate purposes SERI Issuance 5/30/25 5.30% 240 12/15/34 Use of proceeds includes repayment of debt outstanding and general corporate purposes SERI Retirement 6/30/25 2.14% 200 n/a 3Q25 debt maturities Entity Due date Rate Amount ($M) Entergy Corp. Sept. 2025 0.9% 800
Page 41
40 Strong retail sales growth Industrial four-year CAGR now ~13% 6 13 22 37 25E 26E 27E 28E Residential Commercial Industrial Cumulative weather-adjusted retail sales growth vs 2024; TWh ~13% Industrial CAGR 28E vs 24
Page 42
41 Investment for customers supports growth 1. Excludes capital funded with contribution in aid of construction from customers 2. Internal estimates based on last-approved rate base adjusted for assumed changes in the major rate base components and includes CWIP; deferred taxes are deducted from rate base for all OpCos, including E-AR 8 20 30 40 25E 26E 27E 28E Capital investment Depreciation expense Capital investment and depreciation expense; cumulative1; $B Projected rate base1,2; $B 40 45 54 61 69 24E 25E 26E 27E 28E
Page 43
42 Strong credit and cash flow outlook Building capacity for unexpected events, additional growth 12 13 14 15 16 17 18 24 25E 26E 27E 28E 12 13 14 15 16 17 18 24 25E 26E 27E 28E S&P FFO to debt; % Capacity Moody’s downgrade threshold Credit outlooks Moody’s CFO pre-working capital to debt; % S&P downgrade threshold Capacity Cumulative OCF outlook 25E 26E 27E 28E ~$22.5B 25E–28E
Page 44
43 Three-year capital plan by OpCo1 1. Excludes capital funded with contribution in aid of construction from customers E-AR 25E 26E 27E Total Distribution 320 295 320 935 Transmission 85 85 110 280 Generation Renewables and storage 30 410 690 1,130 Other new generation 190 655 640 1,485 Nuclear 235 140 70 445 Other non-nuclear generation 110 65 80 255 Total generation 565 1,270 1,480 3,315 Utility support 105 50 40 195 Total 1,075 1,700 1,950 4,725 Depreciation expense 470 495 500 1,465 E-LA 25E 26E 27E Total Distribution 960 1,215 775 2,950 Transmission 730 1,675 1,440 3,845 Generation Renewables and storage 165 340 1,170 1,675 Other new generation 740 1,600 995 3,335 Nuclear 490 255 230 975 Other non-nuclear generation 180 145 115 440 Total generation 1,575 2,340 2,510 6,425 Utility support 95 80 75 250 Total 3,360 5,310 4,800 13,470 Depreciation expense 820 885 975 2,680 E-MS Distribution 240 340 400 980 Transmission 205 215 110 530 Generation Renewables and storage 145 280 155 580 Other new generation 980 1,255 695 2,930 Nuclear 10 5 5 20 Other non-nuclear generation 80 50 35 165 Total generation 1,215 1,590 890 3,695 Utility support 55 45 55 155 Total 1,715 2,190 1,455 5,360 Depreciation expense 275 285 305 865 E-NO Distribution 120 185 120 425 Transmission 15 5 20 40 Generation Renewables and storage 5 15 10 30 Other new generation - - - - Nuclear - - - - Other non-nuclear generation 25 - - 25 Total generation 30 15 10 55 Utility support 20 20 10 50 Total 185 225 160 570 Depreciation expense 85 85 90 260 $M
Page 45
44 Three-year capital plan by OpCo1 (continued) 1. Excludes capital funded with contribution in aid of construction from customers 2. Depreciation for Entergy Services, LLC is allocated to the OpCos E-TX 25E 26E 27E Total Distribution 560 390 350 1,300 Transmission 225 425 805 1,455 Generation Renewables and storage 250 170 165 585 Other new generation 480 590 125 1,195 Nuclear - - - - Other non-nuclear generation 85 80 65 230 Total generation 815 840 355 2,010 Utility support 40 45 15 100 Total 1,640 1,700 1,525 4,865 Depreciation expense 325 365 390 1,080 SERI 25E 26E 27E Total Distribution - - - - Transmission - - - - Generation Renewables and storage - - - - Other new generation - - - - Nuclear 110 145 110 365 Other non-nuclear generation - - - - Total generation 110 145 110 365 Utility support 25 5 5 35 Total 135 150 115 400 Depreciation expense 125 130 135 390 Entergy Services, LLC Distribution - - - - Transmission - - - - Generation Renewables and storage - - - - Other new generation - - - - Nuclear - - - - Other non-nuclear generation - - - - Total generation - - - - Utility support 90 45 65 200 Total 90 45 65 200 Depreciation expense2 - - - - Total Utility Distribution 2,200 2,425 1,965 6,590 Transmission 1,260 2,405 2,485 6,150 Generation Renewables and storage 595 1,215 2,190 4,000 Other new generation 2,390 4,100 2,455 8,945 Nuclear 845 545 415 1,805 Other non-nuclear generation 480 340 295 1,115 Total generation 4,310 6,200 5,355 15,865 Utility support 430 290 265 985 Total 8,200 11,320 10,070 29,590 Depreciation expense 2,100 2,245 2,395 6,740 $M
Page 46
45 Financial summaries and Regulation G reconciliations
Page 47
46 Earnings summary Calculations may differ due to rounding See Appendix A in the earnings release for additional details 1. 446M and 429M diluted average common shares outstanding for 2Q25 and 2Q24, respectively (Entergy executed a two-for-one forward stock split that was effective with trading on December 13, 2024; 2024 share and per-share information reflects the post-split share count) Table 1: Second quarter earnings summary $ in millions Per share in $1 2Q25 2Q24 2Q25 2Q24 As-reported (after-tax) Utility 599 441 1.34 1.03 Parent & Other (131) (392) (0.29) (0.91) Consolidated 468 49 1.05 0.11 Less adjustments Utility - (112) - (0.26) Parent & Other - (250) - (0.58) Consolidated - (362) - (0.85) Adjusted (non-GAAP) Utility 599 553 1.34 1.29 Parent & Other (131) (142) (0.29) (0.33) Consolidated 468 411 1.05 0.96
Page 48
47 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 December 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 2Q25 2Q24 (Pre-tax except for income taxes and totals; $ in millions) Net income (loss) attributable to ETR Corp. 468 49 Less adjustments: Utility - 2Q24 E-LA global agreement to resolve its FRP extension filing and other retail matters - (151) Utility - income tax effect on adjustment above - 39 P&O - 2Q24 pension lift out - (317) P&O - income tax effect on adjustment above - 67 ETR adjusted earnings (non-GAAP) 468 411 Diluted average number of common shares outstanding (in millions) 446 429 (After-tax, per share in $) Net income (loss) attributable to ETR Corp. 1.05 0.11 Less adjustments: Utility - 2Q24 E-LA global agreement to resolve its FRP extension filing and other retail matters - (0.26) P&O - 2Q24 pension lift out - (0.58) ETR adjusted earnings (non-GAAP) 1.05 0.96
Page 49
48 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 December 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
Page 50
49 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 ~$92M, and average common equity ~$1,018M) and Entergy Utility Holding Co. Table 4: Utility book ROE summary LTM ending June 30, 2025 ($ in millions) E-AR E-LA E-MS E-NO E-TX Utility1 As-reported earnings available to common stock (a) 447 1,128 279 74 313 2,279 Less adjustments: 4Q24 Louisiana state income tax rate change, including an adjustment to E-LA’s associated regulatory liability (9) (22) Total adjustments (b) - (9) - - - (22) Adjusted earnings available to common stock (non-GAAP) (c) = (a) - (b) 447 1,138 279 74 313 2,301 Average common equity (d) 4,568 11,392 2,438 753 3,328 23,410 Adjustment for E-LA affiliate preferred (offset at P&O) Preferred investment, net of noncontrolling interest (beginning / ending average) (e) 4,218 Estimated equity financing for preferred investment (beginning / ending average) (f) 3,188 Dividend income from affiliate preferred, net of noncontrolling interest (g) 301 Estimated debt financing for preferred investment (h) 1,029 Average cost of debt (after-tax) (i) 2.88% Cost of debt financing for preferred investment (after-tax) (j) = (h) x (i) 30 As-reported ROE (a) / (d) 9.8% 9.9% 11.4% 9.8% 9.4% 9.7% Adjusted ROE (non-GAAP) (c) / (d) 9.8% 10.0% 11.4% 9.8% 9.4% 9.8% Adjusted ROE, excluding average affiliate preferred (non-GAAP) (c-g-j) / (d-f) 10.6%
Page 51
ETR