SECOND QUARTER 2025 INVESTOR UPDATE

2 This presentation and the oral statements made in connection herewith contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this presentation and the oral statements made in connection herewith are forward-looking statements made in good faith by CenterPoint Energy, Inc. (“CenterPoint Energy” or the “Company”) and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995, including statements concerning CenterPoint Energy’s expectations, beliefs, plans, objectives, goals, strategies, future operations, events, financial position, earnings and guidance, growth, costs, prospects, capital investments or performance or underlying assumptions and other statements that are not historical facts. You should not place undue reliance on forward-looking statements. You can generally identify our forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “target,” “will,” or other similar words. The absence of these words, however, does not mean that the statements are not forward-looking. Examples of forward-looking statements in this news release or on the earnings conference call include statements about Houston Electric’s Greater Houston Resiliency Initiative (“GHRI”) and System Resiliency Plan (“SRP”) (including with respect to timing, filings related thereto, anticipated benefits, and related matters), the proposed sale of our Ohio natural gas LDC business (including with respect to timing, anticipated benefits, and related matters), Houston Electric’s release of its 15 large 27 megawatt (“MW”) to 32 MW TEEEF units to the San Antonio area and its ability to complete one or more other future transactions involving various sizes of TEEEF units (including with respect to timing, filings related thereto, corresponding reductions in Houston Electric’s TEEEF fleet capacity, anticipated benefits including with respect to rates, expected market demand for the units, and related matters), the timing of, projections for, and anticipated benefits from the settlement of, rate cases for CenterPoint and its subsidiaries, the timing and extent of CenterPoint's recovery, including with regards to its restoration costs for, among other things, the severe weather events in May 2024 (“May 2024 Storm Events”) and Hurricane Beryl, generation transition plans and projects, projects included in CenterPoint's Natural Gas Innovation Plan and System Resiliency Plan, and projects included under its 10-year capital plan, electric demand growth in CenterPoint’s service territories (including our forecasts of, capital investment opportunities related to, the timing of investments related to, and anticipated benefits of such growth), the extent of anticipated benefits of the completed sale of our Louisiana and Mississippi natural gas LDC businesses, future earnings and guidance, including long-term growth rate, dividend growth, customer charges, operations and maintenance expense reductions, financing plans (including with respect to the restoration costs for the May 2024 Storm Events and Hurricane Beryl and the timing and anticipated benefits of any future equity issuances, forward sales, securitization, credit metrics and parent level debt), the timing, funding, and anticipated benefits of our 10-year capital plan, the Company’s 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (“ZENS”) and impacts of the maturity of ZENS, CenterPoint’s continued focus on credit, balance sheet strength, liquidity and credit ratings, tax planning opportunities, future financial performance and results of operations, including with respect to regulatory actions and recoverability of capital investments, customer rate affordability, value creation, opportunities and expectations, and expected customer growth. We have based our forward-looking statements on our management’s beliefs and assumptions based on information currently available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions, and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. Some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking information include, but are not limited to, risks and uncertainties relating to: (1) the business strategies and strategic initiatives, restructurings, joint ventures and acquisitions or dispositions of assets or businesses involving CenterPoint or its industry, including the ability to successfully complete such strategies, initiatives, transactions or plans on the timelines we expect or at all, such as our plan to sell our Ohio natural gas LDC business or the completed sale of our Louisiana and Mississippi natural gas LDC businesses, which we cannot assure you will have the anticipated benefits to us; (2) industrial, commercial and residential growth in CenterPoint’s service territories and changes in market demand, including in relation to the expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, as well as the effects of energy efficiency measures and demographic patterns, and our ability to appropriately estimate and effectively manage business opportunities relating to such matters; (3) CenterPoint’s ability to fund and invest planned capital, and the timely recovery of its investments, including those related to Houston Electric’s GHRI and SRP; (4) the ability to timely execute Houston Electric’s GHRI and SRP; (5) our ability to successfully construct, repair, maintain and restart electric generating facilities, natural gas facilities, TEEEF and electric transmission facilities; (6) the timing and success of, and our ability to obtain approval for, Houston Electric’s release of its large TEEEF units to the San Antonio area, reduction of its TEEEF fleet capacity and reduction of rates to reflect the removal of the large TEEEF units from Houston Electric’s TEEEF fleet, as well as our ability to complete one or more other future transactions involving various sizes of TEEEF units on acceptable terms and conditions within the anticipated timeframe; (7) financial market and general economic conditions, including access to debt and equity capital, inflation, potential for recession, interest rates, and their effect on sales, prices and costs; (8) disruptions to the global supply chain and volatility in commodity prices, including resulting from tariffs, trade agreements, retaliatory trade measures or changes in trade relationships; (9) actions by credit rating agencies, including any potential downgrades to credit ratings; (10) the timing and impact of regulatory proceedings and actions and legal proceedings, including those related to, among other things, the May 2024 Storm Events, Hurricane Beryl, Houston Electric’s TEEEF units and the February 2021 winter storm event, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings or interim rate mechanisms; (11) federal, state and local legislative, executive, regulatory and political actions or developments, including any actions resulting from Hurricane Beryl, actions pertaining to trade (including tariffs, bans, retaliatory trade measures taken against the United States or related government action), tax legislation (including effects of the One Big Beautiful Bill Act ("OBBBA"), Executive Order 14315, and the Inflation Reduction Act ("IRA")) and developments related to the environment; (12) the impact of public health threats; (13) weather variations and other natural phenomena, including severe weather events, and CenterPoint’s ability to mitigate weather impacts, including the approval and timing of securitization issuances; (14) the impact of potential wildfires; (15) changes in business plans; (16) advances in, our ability to timely adopt, develop and deploy, artificial intelligence; (17) the availability of, prices for and our ability to procure materials, supplies or services and scarcity of and changes in labor for current and future projects and operations and maintenance costs; (18) CenterPoint’s ability to timely obtain and maintain necessary licenses and permits from local, federal and other regulatory authorities on acceptable terms and resolve third-party challenges to such licenses or permits, as applicable; (19) CenterPoint’s ability to execute on its initiatives, targets and goals, including its net zero and greenhouse gas emissions reduction goals and operations and maintenance goals; and (20) other factors discussed in CenterPoint’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024 and CenterPoint’s Quarterly Report on Form 10-Q for the quarters ended March 31, 2025 and June 30, 2025, including under “Risk Factors,” “Cautionary Statements Regarding Forward-Looking Information” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in such reports and in other filings with the Securities and Exchange Commission (“SEC”) by CenterPoint, which can be found at www.centerpointenergy.com on the Investor Relations page or on the SEC website at www.sec.gov. This presentation contains time sensitive information that is accurate as of the date hereof (unless otherwise specified as accurate as of another date). Some of the information in this presentation is unaudited and may be subject to change. We undertake no obligation to update the information presented herein except as required by law. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the Investor Relations page of our website. In the future, we will continue to use these channels to distribute material information about the Company and to communicate important information about the Company, key personnel, corporate initiatives, regulatory updates and other matters. Information that we post on our website could be deemed material; therefore, we encourage investors, the media, our customers, business partners and others interested in our Company to review the information we post on our website. Use of Non-GAAP Financial Measures In addition to presenting its financial results in accordance with generally accepted accounting principles (GAAP), including presentation of net income (loss) and diluted earnings (loss) per share, the Company also provides guidance based on non-GAAP income and non-GAAP diluted earnings per share and also provides non-GAAP funds from operations / non-GAAP rating agency adjusted debt (“FFO/Debt”). Generally, a non-GAAP financial measure is a numerical measure of a company’s historical or future financial performance that excludes or includes amounts that are not normally excluded or included in the most directly comparable GAAP financial measure. Please refer to the Appendix for detailed discussion of the use of non-GAAP financial measures presented herein. Cautionary Statement and Other Disclaimer

3 Consistent, Sustainable Growth for Our Investors Positively Impacting our Communities Resilient, Reliable, & Affordable Energy for Customers Targeting top quartile non-GAAP EPS annual growth of 8% in 2025 and dividend per share growth in line with non-GAAP EPS earnings of $1.74 - $1.76 Long-Term Strategic Objectives Q2’25 Updates Delivered $0.29 non-GAAP EPS for the second quarter Maintaining balance sheet health; long-term FFO/Debt(2) target of 14% - 15% through 2030 Reaffirmed 2025 non-GAAP EPS guidance target range of $1.74 - $1.76 which, at the midpoint, would represent 8% growth from 2024 Plan to efficiently fund robust capital investment plan through asset recycling, securitization proceeds and $2.75B of equity or equity-like proceeds through 2030 Announced process to sell Ohio Gas LDC; Derisked ’26 & ’27 equity needs through forward sales of common equity(3) Seeking to keep rates affordable through 1-2% O&M reductions(4), securitization charges ended or extending cost recovery(5), and robust annual customer growth(6) May Storms Financing Order approved; Hurricane Beryl filing in mediation Investing in growth for the benefit of our customers and communities Increased 10-year capital investment plan by $5.5B since FYE 2024 1) Refers to non-GAAP EPS annual growth rate for 2025E – 2030E 2) Based on Moody’s methodology; Adjusted one-time Uri-related items and CEHE storm related costs; FFO/Debt is a non-GAAP measure. Refer to slide 24 for Moody’s TTM Q2 reconciliation 3) Refers to ~$165MM forward sales under ATM & $920MM Equity forward sale 4) O&M average annual reduction target includes Electric and Natural Gas businesses 5) Securitization includes CEHE transition bonds ended in 3Q 2024, SIGECO securitization bonds and proposed May 2024 Storm Event system restoration bonds 6) Internal projection through 2030 Note: Refer to slide 2 for information on forward-looking statements and slides 20-23 and 27 for reconciliations and information on non-GAAP assumptions and measures, including non-GAAP EPS Delivered 14.1% TTM 2Q 2025 FFO/Debt(2) Targeting sustainable non-GAAP EPS and dividend per share growth at the mid-to-high end of 6 - 8% annually through 2030(1) Q2 Update Completed Phase II of the Greater Houston Resiliency Initiative to increase preparedness ahead of the 2025 hurricane season Reached all-parties settlement on System Resiliency Plan filing

4 IN Electric (Docket 45990) Houston Electric (Docket 56211) MN Gas (Docket 23-173) TX Gas (Docket 15513) OH Gas (Docket 24-0832-GA-AIR ) Regulatory Outcome Final Order Issued Key Details Below Final Order Issued Key Details Below Final Order Issued Key Details Below Final Order Issued Key Details Below Proposed Settlement Key Details Below Revenue Request or Impact $80MM ($47MM) 2024: $60.8MM 2025: $42.7MM $5MM Settlement: $59.6MM Requested: $99.5MM Equity Layer / ROE Approved: 48.3% / 9.8%(1) Approved: 43.25% / 9.65% Settlement ROR: 7.07% Approved: 60.6% / 9.8% Settlement: 52.9% / 9.85% Requested: 54.1% / 10.4% Debt Layer / Cost of Debt Approved: 39.5% / 5.1% Approved: 56.75% / 4.3% Settlement ROR: 7.07% Approved: 39.4% / 4.8% Settlement: 47.1% / 4.0% Requested: 45.9% / 4.1% Key Dates(2) Customer rates updated on February 13, 2025, and to be further updated March 1, 2026 Customer rates updated on April 28, 2025 Final order issued on June 27, 2025; final rates will be updated on September 1, 2025 Customer rates updated December 1, 2024 1) Equity % net of cost-free capital and other capital comprised of 11.90% and 0.33%, respectively 2) Future dates are expected Note: Refer to slide 2 for information on forward-looking statements Rate Case Snapshot     

Key Resiliency Actions Resiliency Actions (July 2024 – June 2025) Complete As of May 22, 2025 Target By June 1, 2025 Installing stronger, more storm-resilient poles 26,470 POLES 26,000 POLES Installing automation devices capable of self-healing 5,159 DEVICES 5,150 DEVICES Clearing hazardous vegetation near power lines 6,018 MILES 6,000 MILES Undergrounding power lines 417 MILES 400 MILES 5 ~50% reduction in customer outage minutes compared to the first half of 2024

Expected to strengthen overall resiliency by 30% Expected reductions in outages by over 900M minutes into 2029   Expected savings of ~$25MM per year in storm-related distribution costs Expected avoidance of 500K+ outages during a Beryl-like storm   ~$3.2B(1) Resiliency Capital Investments & Activities of From 2026 through 2028 6 System Resiliency Plan Improving the customer experience through accelerated and increased investment Note: Refer to slide 2 for information on forward-looking statements Automation Devices 100% of lines serving the most customers will include devices capable of self-healing to reduce the impact of outages Undergrounding 50+% of the electric system will be undergrounded to improve resiliency Stronger Distribution Poles 130,000 stronger, storm-resilient poles will be installed new or as replacements, or existing poles braced, to withstand stronger storms Vegetation Management 100% of power lines will be cleared of hazardous vegetation every three years to reduce storm-related outages Modernized Cables 20,150 spans of underground cables will be modernized to reduce the frequency and impact of outages 1) Proposed settlement excludes ~$2.5B of transmission investments included in the original filing

~$5.5B increase to capital plan(1) since YE ‘24 Categories of investment increased this year; incremental opportunities remain 7 Note: Refer to slide 2 for information on forward-looking statements $47.5 $4.3 $0.5 $0.8 $53.0 Capital Plan as of FYE 2024 Electric Transmission Resiliency Investments Texas Gas Revised Capital Plan Incremental Opportunities $ in b ill io ns • 345kV upgrades • Hardening / Resiliency • Increased and accelerated implementation of automation devices • Accelerated pole replacements • Undergrounding of feeders, etc. Electric Transmission Investments Resiliency and Grid Modernization Investments Houston Downtown Revitalization Investments Texas Gas Transmission / High Pressure Distribution Investments 1) Refers to 10-year capital investment plan through 2030

($0.01) $0.01 ($0.06) ($0.01) 81) Refer to slide 20-23 for reconciliation of non-GAAP measures to GAAP measures Q2 2025 vs Q2 2024 Non-GAAP EPS(1) Primary Drivers Q2 2024 Non-GAAP EPS Q2 2025 Non-GAAP EPS $0.36 Growth and Rate Recovery Ongoing Cost Management & Interest ExpenseWeather / Usage Other Electric  $0.01 Growth  $0.04 Depreciation & Other Taxes Gas  $0.02 Rate Recovery Interest Expense  $0.03 O&M  $0.03 Other  $0.01 Equity Dilution Electric  $0.01 Weather $0.29 Note: Refer to slide 27 for information on non-GAAP EPS assumptions and non-GAAP measures and 27 for reconciliations and information on non-GAAP assumptions and measures, including non-GAAP EPS

9 2025 Non-GAAP Earnings Profile Timing of recovery of Texas investments post rate cases will result in a different earnings profile than typical years 50% - 60% 40% - 50% 40% - 50% 50% - 60% Non-Rate Case Profile 2025E Typical Earnings Profile vs. 2025E Profile 2H Earnings % 1H Earnings % Note: Refer to slide 2 for information on forward-looking statements and slides 20-23 and 27 for reconciliations and information on non-GAAP assumptions and measures, including non-GAAP EPS $0.81 $1.75 1H 2025 2025 Midpoint 50% 40%~$0.70 ~46% ~46% of YTD earnings; in line of expectations ~$0.88 Cumulative YTD Non-GAAP Earnings

FY 1Q 2Q FY ‘21 – ‘25 ’21 – ‘30 2024 2025 2025 2025E(3) Plan Plan Electric(2) ~$2.2B ~$1.0B ~$0.7B ~$3.7B ~$14.1B ~$37.3B Natural Gas ~$1.5B ~$0.3B ~$0.4B ~$1.7B ~$7.7B ~$15.5B Corporate and Other ~$36MM ~$12MM ~$1MM ~$20MM ~$0.1B ~$0.2B Total Capital(4) Expenditures ~$3.8B ~$1.3B ~$1.1B ~$5.3B ~$21.8B ~$53.0B 10 Current 5-Yr Plan(1) 10-YR Plan Continued Incremental Capital Opportunities • Electric Transmission Investments (Houston & Indiana Electric) • Resiliency and Grid Modernization Investments • Houston Downtown Revitalization Investments • Texas Gas Transmission / High Pressure Distribution Investments 10-Year Plan Increased $5.5B for Growth Investments Since YE 2024 1) Refers to capital plan from 2021A to 2025E; exclusive of capital investments that are anticipated to be securitized in connection with storm restoration efforts 2) Includes investments in 2021 and 2022 related to capital leases for TEEEF units 3) Represents 2025 capital estimated as of 06/30/2025 4) The calculation may not add down due to rounding Note: Refer to slide 2 for information on forward-looking statements Capital Expenditures by Segment (was $48.5B)(was $4.8B) (was $21.3B)

11 Entity Moody’s (Neg) S&P (Neg) Fitch (Stable) CenterPoint Energy, Inc. Baa2 BBB BBB Houston Electric A2 A A (neg) CERC A3 BBB+ A- SIGECO A1 A - Company Debt Ratings(3) Consolidated FFO To Debt(1)(2) 2024 Full Year 2Q 2025 TTM Moody’s 9.7% 9.8% Adjusted for 1-time items – Moody’s methodology(2) 13.6% 14.1% S&P 12.0% 11.6% Adjusted for 1-time items – S&P methodology 12.9% 12.5% Continued focus on – • Liquidity and commitment to current credit ratings • Plan to incorporate credit supportive, higher equity content instruments • Pursuing securitization; anticipate approximately $1.7B between two filings(4) Upcoming Maturities 2025 2026 2027 CNP (Parent) Senior Notes @ 1.45%, 5.25% - $517MM - Convertible Senior Notes @ 4.25% - $1,000MM - CEHE General Mortgage Bonds @ 2.40% - $300MM - General Mortgage Bonds @ 3.00% - - $300MM Floating Rate Term Loan $500MM - - CERC Private Placement Notes @ 5.02% - $60MM - IGC Senior Notes @ 6.42%, 6.68%, 6.34% - - $26MM SIGECO First Mortgage Bonds @ 3.45% $41MM - - Total $541MM $1,877MM $326MM Consolidated Liquidity Credit Facility Capacity $4.0B CEHE Term Loan (18 month) $0.5B Less: Outstanding Borrowings ~($2.0B) Total Available Liquidity ~$2.5B 1) Based on Moody’s CFO Pre-Working Capital/Debt and S&P’s FFO/Debt methodology with certain one-time adjustments noted on slides 24-25; targets based on plan assumptions; See slides 20-23 for reconciliation to nearest GAAP measures and slide 27 for information regarding non-GAAP measures 2) CNP targets long-term FFO/Debt of 14% - 15% thru 2030 using Moody’s methodology 3) Does not include Vectren LLC and Indiana Gas ratings as they’re not currently active issuers Note: Refer to slide 2 for information on forward-looking statements Continued Focus on Credit and Balance Sheet Strength 4) Ultimate timing of receipt of proceeds subject to change. Currently anticipating Q3 & Q4 ‘25

12 Contacts Ben Vallejo Director Investor Relations and Corporate Planning Tel. (713) 207 – 5461 ben.vallejo@centerpointenergy.com General Contact Tel. (713) 207 – 6500 https://investors.centerpointenergy.com/contact-us

Appendix 13

~74GW Logistics & Transport • Large and medium duty vehicle fleet conversion • Port of Houston Electrification Commercial • Continued expansion of Texas Medical Center • Data Centers Current Peak Load ~21GW 2024 2031E ~31GW Energy Refining and Energy Exports • Continued expansion and electrification of Petrochemical Complex • Refining activity and energy exports Forecasted Peak Load 14 Diverse Houston Electric Load Growth Drivers Underpinned by annual residential customer growth of ~2%(1) 10% to 20% 30% to 35% 40% to 60% Note: Refer to slide 2 for information on forward-looking statements 1) Internal projection through 2030 ~13GW ( 6GW)

15 Regulatory Highlights Stakeholder Benefits Existing Mechanisms for timely recovery of major storm costs Reasonable cost recovery minimizes customer impact and earnings volatility Winter storm gas cost almost fully recovered; MN only remaining state(3) Reasonable cost recovery minimizes customer impact and earnings volatility Generation transition proceedings in Indiana on plan Energy transition good for communities Over 80% of 10-year Capital Plan expected to be recoverable through interim mechanisms (2) (2) Interim Mechanisms ~80% Interim mechanisms with CPCN required ~5% Rate case with forward test year ~10% Traditional rate case ~5% (1) (2) 1) Includes capital expenditures that are expected to be recovered through interim mechanisms but requires approval of Certificate of Public Convenience and Necessity 2) Includes capital expenditures that are expected to be recovered through interim mechanisms and riders. Excludes capital expenditures included in footnote 1 3) Refers to CenterPoint’s recovery of extraordinary gas costs associated with Winter Storm Uri; ~$97MM remaining to be collected Note: Refer to slide 2 for information on forward-looking statements …. Recovery through established regulatory mechanisms Capital Plan & Regulatory Mechanisms

16 aaaaaaaaa Electric Natural Gas(5) 2Q 2025 2Q 2024 2025 vs 2024 Th ro ug hp ut (in G W h) Residential 9,588 9,450 1% Total 30,313 29,034 4% M et er ed C us to m er s (1 ) Residential 2,663,365 2,620,284 2% Total 2,996,732 2,950,593 2% W ea th er v s N or m al (2 ) Cooling Degree Days 1,911 1,342 569 Heating Degree Days 286 4 282 Houston Cooling Degree Days 1,358 1,342 16 Houston Heating Degree Days 22 4 18 2Q 2025 2Q 2024 2025 vs 2024 Th ro ug hp ut (in B cf ) Residential 25 24 5% Commercial and Industrial 86 84 2% Total 111 108 3% M et er ed C us to m er s (1 ) Residential 3,714,672 3,670,751 1% Commercial and Industrial 279,526 272,168 3% Total 3,994,198 3,942,919 1% W ea th er v s N or m al (2 ) Heating Degree Days 293 205 88 Texas Heating Degree Days 23 6 17 Margin Sensitivities CEHE IE TX Gas(3) Per HDD / CDD(4) $50k - $70k $20k - $30k $30k - $40k 1) End of period number of metered customers 2) As compared normal weather for service area 3) Only pertains to HDD 4) As applied to base rates; Per HDD/CDD vs. normal 5) Throughput and Meter Customers are normalized by the exclusion of Louisiana and Mississippi natural gas LDC businesses data in the 2024 and 2025 figures Note: Data as of 06/30/2025 Weather and Throughput Data

17 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TX (E) IN (E) TX (G) MN (G) N. IN (G) OH (G) S. IN (G) ROE / Equity Ratio ’25 Rate Base(3) 9.65% / 43.25% $15.4B 9.8% / 48.3%(1) $2.6B 9.8% / 60.6% $3.1B N/A / N/A(2) $2.4B 9.80% / 46.8%(1) $2.3B N/A / 51.1% $1.5B 9.70% / 46.2%(1) $0.7B Total = $28.0B Regulatory Activity CSIA-5 GRC GRC General Rate Case Final Order Approved Feb 3 Settlement filed April 23 Final Order Approved Mar 13 1) Equity % net of cost-free capital and other adjustments 2) Recent settlement notates an ROR of 7.07% Note: Refer to slide 2 for information on forward-looking statements Regulatory Schedule GRIP Gas Reliability Infrastructure Program CSIA Compliance and System Improvement Adjustment CEP Capital Expenditure Program Rider GRIP CSIA-6 CSIA-7 CSIA-5 CSIA-6 CSIA-7 TCOS Transmission Cost of Service TEEEF Temp. Emergency Electric Energy Facilities DCRF Distribution Cost Recovery Factor TDSIC Trans., Dist., & Storage Sys. Improvement Charge CECA Clean Energy Cost Adjustment ECA Environmental Cost Adjustment TCOS / DCRFTCOS(4) / DCRF(4) / TEEEF CECA / ECA ECA / TDSIC 3) Estimated year-end 2025 Rate Base represents the latest available information; may differ slightly from regulatory filings 4) Both filings were filed on February 28, 2025 GRC GRC CEP / DRR DRR Distribution Replacement Rider

18 Mechanism Date Filed Rates Updated Annual Rev. Req. Increase / (Decrease) C EH E Distribution Cost Recovery Factor (“DCRF”) February 2025 July 2025 $123MM Transmission Cost of Service (“TCOS”) February 2025 April 2025 $64MM General Rate Case March 2024 April 2025 ($47MM) IE General Rate Case December 2023 February 2025 & March 2026 $80MM TX G as Gas Reliability Infrastructure Program (“GRIP”) February 2025 June 2025 $70MM Tax Rider August 2024 June 2025 $15MM M N G as General Rate Case November 2023 September 2025(1) $104MM IN G as Compliance and System Improvement Adjustment (“CSIA”) April 2025 TBD $9MM for N. IN $2MM for S. IN O H G as Distribution Replacement Rider (“DRR”) May 2025 TBD $6MM General Rate Case October 2024 TBD $60MM(2) TOTAL $486MM Note: Refer to slide 2 for information on forward-looking statements Regulatory Filing Updates 1) Interim rates of $69 million and $33 million implemented for 2024 and 2025, respectively; final rates will be implemented in September 2025 in connection with final order 2) $59.6 million based current proposed settlement

19 aaaaaaaaa Note: Refer to slide 2 for information on forward-looking statements Planned Generation Project Timeline (1) 1) Indiana Electric has not entered into any definitive agreement relating to this wind energy generating facility, and there is a significant possibility that either no definitive agreement will be entered into at all or on the expected timeline.

20 aaaaaaaaa Three Months Ended June 30, 2025 Dollars in millions Diluted EPS(1) Consolidated net income (loss) and diluted EPS on a GAAP basis $ 198 $ 0.30 ZENS-related mark-to-market (gains) losses: Equity securities (net of tax expense of $9)(2)(3) (35) (0.05) Indexed debt securities (net of tax benefit of $9)(2) 34 0.05 Impacts associated with mergers and divestitures (net of tax expense of $12)(2)(4) (21) (0.03) Impacts associated with TEEEF Units removed from Rate Base (net of tax benefit of $3)(5) 12 0.02 Consolidated income and diluted EPS on a non-GAAP basis(6) $ 188 $ 0.29 (1) Quarterly diluted EPS on both a GAAP and non-GAAP basis are based on the weighted average number of shares of common stock outstanding during the quarter, and the sum of the quarters may not equal year-to-date diluted EPS (2) Taxes are computed based on the impact removing such item would have on tax expense. Taxes related to the gas LDC sale are booked proportionately by applying the projected annual effective tax rate percentage to income earned each quarter in accordance with GAAP. Additional tax expense related primarily to the write-off of non-deductible goodwill will be reflected in tax expense over the remainder of 2025 and excluded from non-GAAP EPS (3) Comprised of common stock of AT&T Inc., Charter Communications, Inc. , and Warner Bros. Discovery, Inc. (4) Includes gain on early extinguishment of debt with proceeds from the divestiture of the Louisiana and Mississippi natural gas LDC businesses (5) Represents impacts related to temporary emergency electric energy facilities following the removal of the units from our rate regulated business (6) The calculation on a per-share basis may not add down due to rounding Reconciliation: Income (Loss) and Diluted Earnings (Loss) per share to non-GAAP Income and non-GAAP Diluted EPS used in providing annual earnings guidance

21 aaaaaaaaa Three Months Ended June 30, 2024 Dollars in millions Diluted EPS(1) Consolidated net income (loss) and diluted EPS on a GAAP basis $ 228 $ 0.36 ZENS-related mark-to-market (gains) losses: Equity securities (net of taxes of $4)(2)(3) (15) (0.02) Indexed debt securities (net of taxes of $3)(2) 15 0.02 Impacts associated with mergers and divestitures (net of taxes of $1)(2) 6 0.01 Consolidated income and diluted EPS on a non-GAAP basis(4) $ 234 $ 0.36 (1) Quarterly diluted EPS on both a GAAP and non-GAAP basis are based on the weighted average number of shares of common stock outstanding during the quarter, and the sum of the quarters may not equal year-to-date diluted EPS (2) Taxes are computed based on the impact removing such item would have on tax expense (3) Comprised of common stock of AT&T Inc., Charter Communications, Inc., and Warner Bros. Discovery, Inc. (4) The calculation on a per-share basis may not add down due to rounding Reconciliation: Income (Loss) and Diluted Earnings (Loss) per share to non-GAAP Income and non-GAAP Diluted EPS used in providing annual earnings guidance

22 aaaaaaaaa (1) Quarterly diluted EPS on both a GAAP and non-GAAP basis are based on the weighted average number of shares of common stock outstanding during the quarter, and the sum of the quarters may not equal year-to-date diluted EPS (2) Taxes are computed based on the impact removing such item would have on tax expense. Taxes related to the gas LDC sale are booked proportionately by applying the projected annual effective tax rate percentage to income earned each quarter in accordance with GAAP. Additional tax expense related primarily to the write-off of non-deductible goodwill will be reflected in tax expense over the remainder of 2025 and excluded from non-GAAP EPS (3) Comprised of common stock of AT&T Inc., Charter Communications, Inc. , and Warner Bros. Discovery, Inc. (4) Includes $43 million loss on sale associated with the divestiture of our Louisiana and Mississippi natural gas LDC businesses and gain on early extinguishment of debt with proceeds from the divestiture of the Louisiana and Mississippi natural gas LDC businesses (5) Represents impacts related to temporary emergency electric energy facilities following the removal of the units from our rate regulated business (6) The calculation on a per-share basis may not add down due to rounding Reconciliation: Income (Loss) and Diluted Earnings (Loss) per share to non-GAAP Income and non-GAAP Diluted EPS used in providing annual earnings guidance Six Months Ended June 30, 2025 Dollars in millions Diluted EPS(1) Consolidated net income (loss) and diluted EPS on a GAAP basis $ 495 $ 0.76 ZENS-related mark-to-market (gains) losses: Equity securities (net of tax expense of $26)(2)(3) (98) (0.15) Indexed debt securities (net of tax benefit of $25)(2) 96 0.15 Impacts associated with mergers and divestitures (net of tax expense of $12)(2)(4) 27 0.04 Impacts associated with TEEEF Units removed from Rate Base (net of tax benefit of $3)(5) 12 0.02 Consolidated income and diluted EPS on a non-GAAP basis(6) $ 532 $ 0.81

23 aaaaaaaaa (1) Quarterly diluted EPS on both a GAAP and non-GAAP basis are based on the weighted average number of shares of common stock outstanding during the quarter, and the sum of the quarters may not equal year-to-date diluted EPS (2) Taxes are computed based on the impact removing such item would have on tax expense (3) Comprised of common stock of AT&T Inc., Charter Communications, Inc., and Warner Bros. Discovery, Inc. (4) Includes professional fees associated with execution of transactions from the sale of Louisiana and Mississippi LDC businesses (5) The calculation on a per-share basis may not add down due to rounding Reconciliation: Income (Loss) and Diluted Earnings (Loss) per share to non-GAAP Income and non-GAAP Diluted EPS used in providing annual earnings guidance Six Months Ended Twelve Months Ended June 30, 2024 December 31, 2024 Dollars in millions Diluted EPS(1) Dollars in millions Diluted EPS(1) Consolidated net income (loss) and diluted EPS on a GAAP basis $ 578 $ 0.91 $ 1,019 $ 1.58 ZENS-related mark-to-market (gains) losses: Equity securities (net of taxes)(2)(3) 51 0.08 (15) (0.02) Indexed debt securities (net of taxes)(2) (53) (0.09) 11 0.01 Impacts associated with mergers and divestitures (net of taxes)(2)(4) 8 0.01 26 0.04 Consolidated income and diluted EPS on a non-GAAP basis(5) $ 584 $ 0.91 $ 1,041 $ 1.62

24 aaaaaaaaa Twelve month to date ended and as of period ended, respectively ($ in millions) YE 2024 1Q 2025 2Q 2025 Net cash provided by operating activities (A) $2,139 $2,011 $1,995 Add back: Accounts receivable and unbilled revenues, net 84 281 58 Inventory (42) (59) (14) Taxes receivable 27 (123) (135) Accounts payable (210) (64) 37 Other current assets and liabilities (15) (156) 13 Adjusted cash from operations 1,983 1,890 1,954 Plus: Rating agency adjustments(1) 27 99 133 Non-GAAP funds from operations (FFO) (B) $2,010 $1,989 $2,087 Total Debt, Net Short-term Debt: Short-term borrowings 500 500 500 Current portion of VIE Securitization Bonds long-term debt 13 13 13 Indexed debt, net 2 2 1 Current portion of other long-term debt 51 1,310 540 Long-term Debt: VIE Securitization bonds, net 308 308 301 Other long-term debt, net 20,089 20,054 20,263 Total Debt, net (C) 20,963 22,187 21,618 Plus: Rating agency adjustments(1) (277) (1,588) (416) Non-GAAP rating agency adjusted debt (D) $20,686 $20,599 $21,202 Net cash provided by operating activities / total debt, net (A/C) 10.2% 9.1% 9.2% CFO Pre-Working Capital/Debt– Moody’s(1) (B/D) 9.7% 9.7% 9.8% CNP Adjustments to FFO for 1-time items (E) 563 635 666 CNP Adjustments to Debt for 1-time items (F) (1,707) (1,728) (1,714) Non-GAAP FFO / Non-GAAP adjusted debt (“FFO/Debt”) Adjusted for 1-time items(2) (B + E / D + F) 13.6% 13.9% 14.1% Based on Moody’s Methodology 1) Based on Moody’s methodology, including adjustments related to operating lease costs, stock dividends, non-recurring items, and net defined benefit plan contributions 2) CNP further reduced FY 2024 for the associated one-time of $134MM Winter Storm Uri related debt as well as CEHE storm related costs (FFO: $563; Debt: $1,573). Please see note 17 of the 2024 Form 10-K for supplemental disclosure of cash flow information Reconciliation: Net Cash Provided by Operating Activities and Total Debt, Net to non- GAAP Funds from Operations (FFO) and non-GAAP Adj. Debt

25 1) Based on S&P’s methodology, including adjustments related to operating lease costs, preferred stock dividends, non-recurring items, and net defined benefit plan contributions 2) CNP removes Winter Storm Uri related debt. Please see note 17 of the 2024 Form 10-K for supplemental disclosure of cash flow information 3) Excludes CEHE storm related debt cost of $1,617MM Reconciliation: Gross Margin and Total Debt, Net to non-GAAP Funds from Operations (FFO) and non-GAAP Rating Agency Adjusted Debt Based on S&P’s Methodology Twelve month to date ended and as of period ended, respectively ($ in millions) YE 2024 1Q 2025 2Q 2025 Unadjusted EBITDA Gross Margin 6,925 7,006 6,976 O&M (2,949) (2,987) (3,024) Taxes and Other (547) (557) (556) Unadjusted EBITDA 3,429 3,462 3,396 Less: Cash interest paid 805 867 888 Less: Cash taxes paid (9) - (10) Plus: Rating agency adjustments(1) (161) (163) (62) Non-GAAP funds from operations (FFO) 2,472 2,432 2,456 Total Debt, Net Short-term Debt: Short-term borrowings 500 500 500 Current portion of VIE Securitization Bonds long-term debt 13 13 13 Indexed debt, net 2 2 1 Current portion of other long-term debt 51 1,310 540 Long-term Debt: VIE Securitization bonds, net 308 308 301 Other long-term debt, net 20,089 20,054 20,263 Total Debt, net 20,963 22,187 21,618 Plus: Rating agency adjustments(2) (284) (1,507) (377) Non-GAAP rating agency adjusted debt 20,679 20,680 21,241 Unadjusted EBITDA / total debt, net 16.4% 15.6% 15.7% FFO/Debt (S&P) 12.0% 11.8% 11.6% FFO/Debt (S&P) – adjusted for one-time items (2)(3) 12.9% 12.8% 12.5%

26 aaaaaaaaa Information Location Electric  Estimated 2024 year-end rate base by jurisdiction  Authorized ROE and capital structure by jurisdiction  Definition of regulatory mechanisms  Projected regulatory filing schedule Regulatory Information – Electric Natural Gas  Estimated 2024 year-end rate base by jurisdiction  Authorized ROE and capital structure by jurisdiction  Definition of regulatory mechanisms  Projected regulatory filing schedule Regulatory Information – Gas Estimated amortization for pre-tax equity earnings related to Houston Electric’s securitization bonds Regulatory Information – Electric (Pg. 5) Rate changes and Interim mechanisms filed Form 10-K – Rate Change Applications section Regulatory Information

27 Additional Information Use of Non-GAAP Financial Measures In this presentation and the oral statements made in connection herewith, CenterPoint Energy presents, based on net income (loss), diluted earnings (loss) per share, and net cash provided by operating activities to total debt, net, and gross margin to total debt, net, the following financial measures which are not generally accepted accounting principles (“GAAP”) financial measures: non-GAAP income, non-GAAP diluted earnings per share (“non-GAAP EPS”), as well as non-GAAP funds from operations / non-GAAP rating agency adjusted debt (Moody’s and S&P) (“FFO/Debt”). Generally, a non-GAAP financial measure is a numerical measure of a company’s historical or future financial performance that excludes or includes amounts that are not normally excluded or included in the most directly comparable GAAP financial measure. 2024 and 2025 non-GAAP EPS excluded and 2025 non-GAAP EPS guidance excludes: (a) Earnings or losses from the change in value of ZENS and related securities, (b) Gain, losses and impact, including related expenses, associated with mergers and divestitures, such as the divestiture of our Louisiana and Mississippi natural gas LDC businesses, and (c) With respect to 2025 non-GAAP EPS and 2025 non-GAAP EPS guidance, impacts related to temporary emergency electric facilities ("TEEEF") once they are no longer part of our rate-regulated business. In providing 2024 and 2025 non-GAAP EPS and 2025 non-GAAP EPS guidance, CenterPoint Energy does not consider the items noted above and other potential impacts such as changes in accounting standards, impairments or other unusual items, which could have a material impact on GAAP reported results for the applicable guidance period. The 2025 non-GAAP EPS guidance ranges also consider assumptions for certain significant variables that may impact earnings, such as customer growth and usage including normal weather, throughput, recovery of capital invested, effective tax rates, financing activities and related interest rates, and regulatory and judicial proceedings. To the extent actual results deviate from these assumptions, the 2025 non-GAAP EPS guidance range may not be met, or the projected annual non-GAAP EPS growth rate may change. CenterPoint Energy is unable to present a quantitative reconciliation of forward-looking non-GAAP diluted earnings per share without unreasonable effort because changes in the value of ZENS and related securities, future impairments, and other unusual items are not estimable and are difficult to predict due to various factors outside of management’s control. Funds from operations (Moody’s) excludes from net cash provided by operating activities accounts receivable and unbilled revenues, net, inventory, taxes receivable, accounts payable, and other current assets and liabilities, and includes certain adjustments consistent with Moody’s methodology, including adjustments related to operating lease costs, stock dividends, non-recurring items, and net defined benefit plan contributions. Non-GAAP rating agency adjusted debt (Moody’s) adds to Total Debt, net certain adjustments consistent with Moody’s methodology, including operating lease costs, stock dividends, non-recurring items, and net defined benefit plan contributions and further adjustments related to Winter Storm Uri debt as well as CEHE storm related costs. Funds from operations (S&P) excludes from gross margin, O&M, taxes and other, cash interest paid and cash taxes paid, and includes certain adjustments consistent with S&P's methodology, including adjustments related to operating lease costs, preferred stock dividends, non- recurring items, and net defined benefit plan contributions. Non-GAAP rating agency adjusted debt (S&P) adds to Total Debt, net certain adjustments consistent with S&P's methodology, including adjustments related to Winter Storm Uri related debt and CEHE storm related debt. The appendix to this presentation contains a reconciliation of net income (loss) and diluted earnings (loss) per share to the basis used in providing guidance, as well as a reconciliation of net cash provided by operating activities / total debt, net (and gross margin to total debt, net) to FFO/Debt. Management evaluates the Company’s financial performance in part based on non-GAAP income, non-GAAP EPS and long-term FFO/Debt. Management believes that presenting these non-GAAP financial measures enhances an investor’s understanding of CenterPoint Energy’s overall financial performance by providing them with an additional meaningful and relevant comparison of current and anticipated future results across periods. The adjustments made in these non-GAAP financial measures exclude items that Management believes do not most accurately reflect the Company’s fundamental business performance. These excluded items are reflected in the reconciliation tables, where applicable. CenterPoint Energy’s non-GAAP income, non-GAAP EPS and FFO/Debt financial measures should be considered as a supplement to, and not as a substitute for, or superior to, net income (loss), diluted earnings (loss) per share, net cash provided by operating activities to total debt, net and gross margin to total debt, net, which, respectively, are the most directly comparable GAAP financial measures. These non-GAAP financial measures also may be different than non-GAAP financial measures used by other companies. Net Zero Disclaimer CenterPoint Energy’s Scope 1 greenhouse gas ("GHG") emissions estimates are calculated from GHG emissions that directly come from its operations. CenterPoint Energy’s Scope 2 GHG emissions estimates are calculated from GHG emissions that indirectly come from its energy usage, but because Texas is in an unregulated market, its Scope 2 GHG emissions estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and exclude GHG emissions related to purchased power between 2024E- 2026E. CenterPoint Energy’s Scope 3 GHG emissions estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the U.S. Energy Information Administration (EIA) Form EIA-176 reports and do not take into account the GHG emissions of transport customers and GHG emissions related to upstream extraction. CenterPoint Energy's analysis and plan for execution to achieve its Net Zero GHG emissions (Scope 1 and certain Scope 2) by 2035 goals and its 20-30% reduction in Scope 3 GHG emissions by 2035 as compared to 2021 levels goal require it to make a number of assumptions. These goals and underlying assumptions involve risks and uncertainties and are not guarantees. Should one or more of these underlying assumptions require updating, CenterPoint Energy’s actual results and ability to make progress towards and achieve its Net Zero and GHG emissions reduction goals and the timing thereof could differ materially from its expectations. Certain of the assumptions that could impact its ability to make progress towards and meet its Net Zero and GHG emissions reduction goals and the timing thereof include, but are not limited to: GHG emission levels, service territory size and capacity needs remaining in line with company expectations (including with respect to demand for our services); the ability to appropriately estimate and effectively manage business opportunities from new customers and load growth resulting from, among other things, expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics in our service territories; regulatory approvals related to Indiana Electric’s generation transition plan and CenterPoint Energy's ability to obtain such approvals; impacts on affordability of customer rates; customer demand for GHG emissions free or lower GHG emissions energy; impacts of regulations, executive action or legislation, including those related to the environment and tax matters (including the effects of the OBBBA, Executive Order 14315 and the IRA and any further changes to or the repeal of the IRA); impacts of future carbon pricing regulation or legislation; price, availability and regulation of carbon offsets; price of fuel, such as natural gas; cost of energy generation technologies, such as wind and solar, natural gas and storage solutions; adoption of alternative energy by the public, including adoption of electric vehicles; rate of technology innovation with regards to alternative energy resources; CenterPoint Energy’s ability to implement its modernization plans for its pipelines and facilities; the ability to complete and timely implement generation alternatives to Indiana Electric’s coal generation and retirement or fuel conversion dates of Indiana Electric’s coal facilities by 2035; the ability to construct and/or permit new natural gas pipelines; the ability to procure resources needed to build at a reasonable cost, the lack of or scarcity of resources and labor, the lack of any project cancellations, construction delays or overruns (including as a result of tariffs, legislation, bans, potential retaliatory trade measures taken against the United States or related governmental action) and the ability to appropriately estimate costs of new generation; impact of any supply chain disruptions; changes in applicable standards, metrics, methodologies or frameworks; and enhancement of energy efficiencies.