The following combined discussion and analysis should be read in combination with the Interim Condensed Financial Statements contained in Item 1 herein and the Registrants’ combined 2025 Form 10-K. The discussion of CenterPoint Energy’s consolidated financial information includes the results of CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp., which, along with CenterPoint Energy, Inc. are collectively referred to as the Registrants. Where appropriate, information relating to a specific Registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this combined Form 10-Q, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric and CERC, unless otherwise stated. No Registrant makes any representation as to the information relating to the other Registrants or the subsidiaries of CenterPoint Energy, Inc. other than itself or its subsidiaries. RECENT EVENTS Large-Load Customers. The PUCT has begun the process of implementing Texas Senate Bill 6 through various rulemaking processes, focused on establishing financial, operational, and interconnection requirements for large-load customers to ensure grid reliability and prevent stranded infrastructure costs. On June 18, 2026, the PUCT approved ERCOT’s Batch Zero process for large-user connection requests with the stated goal of ensuring large electricity users like data centers only connect in quantities and locations the Texas grid can reliably support. Houston Electric estimates that approximately 14 gigawatts of its potential large-load customers are eligible to be considered part of ERCOT’s Batch Zero process, including the execution of Facilities Extension Agreements with Houston Electric and posting of financial security. The amount of gigawatts ultimately connected to the Houston Electric system, the actual amount of electricity ultimately used by these customers, and the ultimate timing of these additional load connections and energization, if at all, remain uncertain due to a variety of factors, including, but not limited to ERCOT approval into Batch Zero, including into base load or studied load, timing of construction, potential legislative, regulatory, and other government actions, and availability of materials. In the third quarter of 2026, customers provided or committed approximately $900 million in either contributions in aid of construction or financial security to Houston Electric, a portion of which may be returned to large-load customers depending on project outcomes and contractual requirements. These amounts will continue to change as projects move through ERCOT reviews, load allocations are refined, and customers either advance toward construction and energization or exit the process. Updated 10-Year Capital Plan. In July 2026, CenterPoint Energy announced an increase in its 10-year capital plan of $1.2 billion to reflect total planned capital expenditures of approximately $66.7 billion through 2035. The plan is expected to advance economic growth, enhance the experience of the Registrants’ customers and deliver consistent value for stakeholders across the Registrants’ jurisdictions. Equity Distribution Agreement. On May 15, 2026, CenterPoint Energy entered into the 2026 Equity Distribution Agreement with respect to the offering and sale from time to time of shares of Common Stock, having an aggregate gross sales price of up to $1 billion. Sales of Common Stock under the 2026 Equity Distribution Agreement may be made by any method permitted by applicable law and deemed to be an “at the market offering” as defined in Rule 415 of the Securities Act. CenterPoint Energy may also enter into one or more forward sale agreements pursuant to master forward confirmations and related supplemental confirmations. Upon entry into the Equity Distribution Agreement, CenterPoint Energy terminated the previous at-the-market program pursuant to the 2024 Equity Distribution Agreement. For further information, see Note 15 to the Interim Condensed Financial Statements. CenterPoint Energy Appointment of Chief Accounting Officer. On February 23, 2026, CenterPoint Energy announced the appointment of Russell K. Wright to the position of Vice President and Chief Accounting Officer of CenterPoint Energy, effective March 2, 2026. Treasury Notice 2026-7. On February 18, 2026, Treasury Notice 2026-7 was issued. This notice allows an election to modify the computation of AFSI by including an adjustment to deduct certain repair and maintenance costs that are capitalized in the applicable financial statement. TEEEF. In June 2025, Houston Electric entered into the ERCOT Transaction, subject to PUCT approval, to release its 15 large (27 MW to 32 MW) TEEEF units to ERCOT at CPS Energy facilities to serve the greater San Antonio region until March 2027 unless terminated earlier pursuant to the provisions of the ERCOT Transaction, reduce its TEEEF fleet capacity and reduce its rates to reflect removal of the large TEEEF units from its fleet. Following the completion of service in the San Antonio area, Houston Electric anticipates that it would complete one or more future transactions involving its large TEEEF units. As the large TEEEF units would not be available to serve Houston Electric customers during such time, Houston Electric plans to continue to not charge customers for these units for any future periods. In November 2025, Houston Electric proposed to remove its five medium (5.7 MW) TEEEF units and to remove the associated lease costs from its rates effective January 1, 45 Table of Contents 2026. On June 26, 2026, Houston Electric filed a stipulation and agreement supporting removal of the 15 large units and 5 medium units effective May 1, 2025 and January 1, 2026, respectively, an agreed motion for interim rates effective August 15, 2026, settlement testimony, and agreed motion to admit evidence and remand proceeding back to the PUCT. On June 29, 2026, SOAH granted the requested motions and remanded the proceeding to the PUCT. For additional information, see Note 6 to the Interim Condensed Financial Statements. Regulatory Proceedings. For further information, see Note 6 to the Interim Condensed Financial Statements. For information related to our pending and completed regulatory proceedings to date in 2026, see “Liquidity and Capital Resources —Regulatory Matters” below. Debt Transactions. For information about debt transactions to date in 2026, see Note 9 to the Interim Condensed Financial Statements. 46 Table of Contents CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS For information regarding factors that may affect the future results of our consolidated operations, see “Risk Factors” in Part I, Item 1A of the Registrants’ combined 2025 Form 10-K. Net income (loss) for the three and six months ended June 30, 2026 and 2025 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Favorable (Unfavorable) 2026 2025 Favorable (Unfavorable) (in millions) Electric $ 237 $ 171 $ 66 $ 377 $ 279 $ 98 Natural Gas 80 86 (6) 330 314 16 Corporate and Other (1) (73) (59) (14) (147) (98) (49) Total CenterPoint Energy $ 244 $ 198 $ 46 $ 560 $ 495 $ 65 (1)Includes unallocated corporate costs, interest income and interest expense and intercompany eliminations. Three months ended June 30, 2026 compared to three months ended June 30, 2025 Net income increased $46 million primarily due to the following items: •an increase in net income of $66 million for the Electric reportable segment, as further discussed below; •a decrease in net income of $6 million for the Natural Gas reportable segment, as further discussed below; and •an increase in net loss of $14 million for the Corporate and Other reportable segment, primarily due to a $21 million gain on the early extinguishment of debt recognized during the second quarter of 2025 that did not recur, an increase in operating expense and the unfavorable net impact of the mark-to-market valuations on the ZENS indexed debt securities derivative and ZENS-related securities, partially offset by $4 million from a release of a state unrecognized tax benefit upon statute of limitations expiration and $1 million of lower borrowing costs. Six months ended June 30, 2026 compared to six months ended June 30, 2025 Net income increased $65 million primarily due to the following items: •an increase in net income of $98 million for the Electric reportable segment, as further discussed below; •an increase in net income of $16 million for the Natural Gas reportable segment, as further discussed below; and •an increase in net loss of $49 million for the Corporate and Other reportable segment, due to an $18 million tax benefit recognized in 2025 related to the sale of the Louisiana and Mississippi natural gas businesses that did not recur, a $21 million accrued tax expense related to the anticipated divestiture of the Ohio natural gas business expected to close in the fourth quarter of 2026, a $21 million gain on the early extinguishment of debt recognized in 2025 that did not recur, and the unfavorable net impact of the mark-to-market valuations on the ZENS indexed debt securities derivative and ZENS-related securities, partially offset by a $4 million release of a state unrecognized tax benefit upon the expiration of the statute of limitations. The remaining variance is primarily driven by income taxes and intersegment interest. Income Tax Expense. For a discussion of effective tax rate per period, see Note 10 to the Interim Condensed Financial Statements. 47 Table of Contents CENTERPOINT ENERGY’S RESULTS OF OPERATIONS BY REPORTABLE SEGMENT CenterPoint Energy’s CODM views net income as the measure of profit or loss for the reportable segments. Segment results include inter-segment interest income and expense, which may result in inter-segment profit and loss. The following discussion of CenterPoint Energy’s results of operations is further separated into two reportable segments, Electric and Natural Gas. Electric (CenterPoint Energy) For information regarding factors that may affect the future results of operations of CenterPoint Energy’s Electric reportable segment, see “Risk Factors — Risk Factors Affecting Operations — Electric Generation, Transmission and Distribution,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Part I, Item 1A of the Registrants’ combined 2025 Form 10-K. The following table provides summary data of CenterPoint Energy’s Electric reportable segment: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Favorable (Unfavorable) 2026 2025 Favorable (Unfavorable) (in millions, except operating statistics) Revenues $ 1,372 $ 1,191 $ 181 $ 2,581 $ 2,257 $ 324 Expenses: Utility natural gas, fuel and purchased power 67 65 (2) 148 139 (9) Operation and maintenance 532 523 (9) 1,045 1,007 (38) Depreciation and amortization 283 230 (53) 552 440 (112) Taxes other than income taxes 83 80 (3) 168 158 (10) Total expenses 965 898 (67) 1,913 1,744 (169) Operating Income 407 293 114 668 513 155 Other Income (Expense): Interest expense and other finance charges (138) (106) (32) (269) (207) (62) Other income, net 23 25 (2) 49 39 10 Income Before Income Taxes 292 212 80 448 345 103 Income tax expense 55 41 (14) 71 66 (5) Net Income $ 237 $ 171 $ 66 $ 377 $ 279 $ 98 Throughput (in GWh): Residential 9,384 9,588 (2) % 15,782 16,231 (3) % Total 30,306 30,313 — % 55,263 55,064 — % Weather (percentage of normal weather for service area): Cooling degree days 105 % 114 % (9) % 116 % 117 % (1) % Heating degree days 59 % 80 % (21) % 88 % 101 % (13) % Number of metered customers at end of period: Residential 2,705,111 2,663,365 2 % 2,705,111 2,663,365 2 % Total 3,042,231 2,996,732 2 % 3,042,231 2,996,732 2 % 48 Table of Contents The following table provides variance explanations for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 as well as for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 by major income statement caption for CenterPoint Energy’s Electric reportable segment: Favorable (Unfavorable) Three Months Ended June 30, 2026 vs 2025 Six Months Ended June 30, 2026 vs 2025 (in millions) Revenues Customer rates and the impact of the change in rate design $ 82 $ 131 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 36 89 Customer growth 7 12 Energy efficiency, partially offset in operation and maintenance below — 1 Pass-through revenues, offset in operation and maintenance below (5) — Miscellaneous revenues, including service connections and off-system sales (3) 11 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below 62 87 Weather, efficiency improvements and other usage impacts (4) (16) Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below 6 9 Total $ 181 $ 324 Utility natural gas, fuel and purchased power Cost of purchased power, offset in revenues above $ — $ 24 Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above (2) (33) Total $ (2) $ (9) Operation and maintenance Transmission costs billed by transmission providers, offset in revenues above $ (19) $ (47) Contract services 12 4 Energy efficiency, and other pass-through, offset in revenues above — (2) Corporate support services 4 2 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items (2) (2) Labor and benefits 5 11 All other operation and maintenance expense, including materials and supplies and insurance (9) (4) Total $ (9) $ (38) Depreciation and amortization Ongoing additions to plant-in-service $ (29) $ (58) Amortization of regulatory assets 28 37 Lease expense associated with TEEEF units no longer eligible for regulatory deferral (10) (34) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items (42) (57) Total $ (53) $ (112) Taxes other than income taxes Incremental capital projects placed in service, and the impact of updated property tax rates $ (3) $ (10) Total $ (3) $ (10) Interest expense and other finance charges Changes in outstanding debt $ (9) $ (26) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (18) (28) Other, primarily AFUDC and impacts of regulatory deferrals (5) (8) Total $ (32) $ (62) Other income, net Other income, including AFUDC - equity and intersegment interest income $ (2) $ 10 Total $ (2) $ 10 Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 10 to the Interim Condensed Financial Statements. 49 Table of Contents Natural Gas (CenterPoint Energy) For information regarding factors that may affect the future results of operations of CenterPoint Energy’s Natural Gas reportable segment, see “Risk Factors — Risk Factors Affecting Operations — Natural Gas,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Part I, Item 1A of the Registrants’ combined 2025 Form 10-K. The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Favorable (Unfavorable) 2026 2025 Favorable (Unfavorable) (in millions, except operating statistics) Revenues $ 777 $ 751 $ 26 $ 2,542 $ 2,604 $ (62) Expenses: Utility natural gas and fuel 214 236 22 1,104 1,169 65 Non-utility cost of revenues, including natural gas — 2 2 1 3 2 Operation and maintenance 212 195 (17) 470 460 (10) Depreciation and amortization 157 137 (20) 305 284 (21) Taxes other than income taxes 64 56 (8) 135 130 (5) Total expenses 647 626 (21) 2,015 2,046 31 Operating Income 130 125 5 527 558 (31) Other Income (Expense): Loss on sale — — — — (43) 43 Interest expense and other finance charges (46) (43) (3) (116) (102) (14) Other income, net 7 15 (8) 11 17 (6) Income Before Income Taxes 91 97 (6) 422 430 (8) Income tax expense 11 11 — 92 116 24 Net Income $ 80 $ 86 $ (6) $ 330 $ 314 $ 16 Throughput (in Bcf): Residential 22 25 (12) % 117 143 (18) % Commercial and Industrial 81 86 (6) % 209 234 (11) % Total 103 111 (7) % 326 377 (14) % Weather (percentage of 10-year average for service area): Heating degree days 84 % 88 % (4) % 90 % 97 % (7) % Number of metered customers at end of period: Residential 3,739,276 3,714,672 1 % 3,739,276 3,714,672 1 % Commercial and Industrial 285,466 279,526 2 % 285,466 279,526 2 % Total 4,024,742 3,994,198 1 % 4,024,742 3,994,198 1 % 50 Table of Contents The following table provides variance explanations for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 as well as for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 by major income statement caption for CenterPoint Energy’s Natural Gas reportable segment: Favorable (Unfavorable) Three Months Ended June 30, 2026 vs 2025 Six Months Ended June 30, 2026 vs 2025 (in millions) Revenues Cost of natural gas, offset in utility natural gas and fuel below $ (21) $ (6) Gross receipts tax, offset in taxes other than income taxes below 2 5 Weather and usage (2) (20) Non-volumetric and miscellaneous revenue 6 7 Energy efficiency and other pass-through, offset in operation and maintenance below 3 7 Non-utility revenues 1 2 Customer growth 2 7 Customer rates and impact of the change in rate design 35 84 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — (148) Total $ 26 $ (62) Utility natural gas and fuel Cost of natural gas, offset in revenues above $ 22 $ 7 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 58 Total $ 22 $ 65 Operation and maintenance All other operations and maintenance expense, including bad debt expense $ (15) $ (16) Energy efficiency and other pass-through, offset in revenues above (3) (7) Contract services (5) (13) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 20 Labor and benefits 4 3 Corporate support services 2 3 Total $ (17) $ (10) Depreciation and amortization Ongoing additions to plant-in-service $ (17) $ (37) Amortization of regulatory assets (3) 2 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 14 Total $ (20) $ (21) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (2) $ (5) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 8 Incremental capital projects placed in service, and the impact of updated property tax rates (6) (8) Total $ (8) $ (5) Loss on sale Loss on sale of Louisiana and Mississippi natural gas LDC businesses $ — $ 43 Total $ — $ 43 Interest expense and other finance charges Changes in outstanding debt $ (12) $ (35) Other, primarily AFUDC and impacts of regulatory deferrals 9 11 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 10 Total $ (3) $ (14) Other income, net Other income, including AFUDC - Equity and intersegment interest income $ (8) $ (6) Total $ (8) $ (6) Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 10 to the Interim Condensed Financial Statements. 51 Table of Contents HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS Houston Electric’s CODM views net income as the measure of profit or loss for its single reportable segment. Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and Houston Electric’s ability to recover its regulatory assets. For more information regarding factors that may affect the future results of operations of Houston Electric’s business, see “Risk Factors — Risk Factors Affecting Operations — Electric Generation, Transmission and Distribution,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Part I, Item 1A of the Registrants’ combined 2025 Form 10-K and in Part II, Item 1A of this combined Form 10-Q. The following table provides summary data of Houston Electric’s single reportable segment: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Favorable (Unfavorable) 2026 2025 Favorable (Unfavorable) (in millions, except operating statistics) Revenues: TDU $ 1,104 $ 1,008 $ 96 $ 2,068 $ 1,892 $ 176 Bond Companies 63 — 63 90 — 90 Total revenues 1,167 1,008 159 2,158 1,892 266 Expenses: Operation and maintenance, excluding Bond Companies 490 482 (8) 962 930 (32) Depreciation and amortization, excluding Bond Companies 202 196 (6) 417 375 (42) Taxes other than income taxes 82 78 (4) 163 153 (10) Bond Companies 45 — (45) 62 — (62) Total expenses 819 756 (63) 1,604 1,458 (146) Operating Income 348 252 96 554 434 120 Other Income (Expense): Interest expense and other finance charges (99) (90) (9) (199) (176) (23) Interest expense on Securitization Bonds (18) — (18) (28) — (28) Other income, net 19 15 4 42 23 19 Income Before Income Taxes 250 177 73 369 281 88 Income tax expense 48 36 (12) 71 56 (15) Net Income $ 202 $ 141 $ 61 $ 298 $ 225 $ 73 Throughput (in GWh): Residential 9,071 9,272 (2) % 15,125 15,545 (3) % Total 29,020 29,109 — % 52,684 52,913 — % Weather (percentage of 10-year average for service area): Cooling degree days 106 % 117 % (11) % 119 % 120 % (1) % Heating degree days 64 % 110 % (46) % 105 % 92 % 13 % Number of metered customers at end of period: Residential 2,570,229 2,528,981 2 % 2,570,229 2,528,981 2 % Total 2,887,519 2,842,718 2 % 2,887,519 2,842,718 2 % 52 The following table provides variance explanations for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 as well as for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 by major income statement caption for Houston Electric: Favorable (Unfavorable) Three Months Ended June 30, 2026 vs 2025 Six Months Ended June 30, 2026 vs 2025 (in millions) Revenues Customer rates and the impact of the change in rate design $ 63 $ 88 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 36 89 Customer growth 6 11 Energy efficiency, partially offset in both operation and maintenance below — 1 Miscellaneous revenues — 5 Weather, efficiency improvements and other usage impacts (9) (18) Bond Companies, offset in other line items below 63 90 Total $ 159 $ 266 Operation and maintenance, excluding Bond Companies Transmission costs billed by transmission providers, offset in revenues above $ (19) $ (47) Contract services 11 6 Energy efficiency, offset in revenues above — (1) Corporate support services 4 2 Labor and benefits 6 13 All other operation and maintenance expense, including materials and supplies and insurance (10) (5) Total $ (8) $ (32) Depreciation and amortization, excluding Bond Companies Ongoing additions to plant-in-service $ (24) $ (46) Amortization of regulatory assets 27 37 Lease expense associated with TEEEF units no longer eligible for regulatory deferral (9) (33) Total $ (6) $ (42) Taxes other than income taxes Incremental capital projects placed in service, and the impact of changes to tax rates $ (4) $ (10) Total $ (4) $ (10) Bond Companies Operations and maintenance and depreciation expense, offset in revenues above $ (45) $ (62) Total $ (45) $ (62) Interest expense and other finance charges Changes in outstanding debt $ (6) $ (18) Other, primarily AFUDC and impacts of regulatory deferrals (3) (5) Total $ (9) $ (23) Interest expense on Securitization Bonds Change in outstanding principal balance, offset in revenues above $ (18) $ (28) Total $ (18) $ (28) Other income, net Other income, including AFUDC - equity and affiliate interest income $ 4 $ 19 Total $ 4 $ 19 Income Tax Expense. For a discussion of effective tax rate per period, see Note 10 to the Interim Condensed Financial Statements. 53 Table of Contents CERC CONSOLIDATED RESULTS OF OPERATIONS CERC’s CODM views net income as the measure of profit or loss for its single reportable segment. CERC’s results of operations are affected by seasonal fluctuations in the demand for natural gas. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates CERC charges, debt service costs and income tax expense, CERC’s ability to collect receivables from customers and CERC’s ability to recover its regulatory assets. For more information regarding factors that may affect the future results of operations for CERC’s business, see “Risk Factors — Risk Factors Affecting Operations — Natural Gas,” “— Risk Factors Affecting Regulatory, Environmental and Legal Risks,” “— Risk Factors Affecting Financial, Economic and Market Risks,” “— Risk Factors Affecting Safety and Security Risks” and “— General and Other Risks” in Part I, Item 1A of the Registrants’ combined 2025 Form 10-K. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 Favorable (Unfavorable) 2026 2025 Favorable (Unfavorable) (in millions, except operating statistics) Revenues $ 760 $ 731 $ 29 $ 2,457 $ 2,519 $ (62) Expenses: Utility natural gas 211 231 20 1,076 1,140 64 Non-utility cost of revenues, including natural gas — 2 2 1 3 2 Operation and maintenance 203 187 (16) 452 443 (9) Depreciation and amortization 151 131 (20) 293 273 (20) Taxes other than income taxes 64 56 (8) 134 129 (5) Total expenses 629 607 (22) 1,956 1,988 32 Operating Income 131 124 7 501 531 (30) Other Income (Expense): Gain on sale — — — — 52 (52) Interest expense and other finance charges (44) (39) (5) (110) (95) (15) Other income, net 6 12 (6) 9 14 (5) Income Before Income Taxes 93 97 (4) 400 502 (102) Income tax expense 11 11 — 88 111 23 Net Income $ 82 $ 86 $ (4) $ 312 $ 391 $ (79) Throughput (in Bcf): Residential 22 24 (8) % 114 139 (18) % Commercial and Industrial 71 75 (5) % 187 211 (11) % Total 93 99 (6) % 301 350 (14) % Weather (percentage of 10-year average for service area): Heating degree days 85 % 88 % (3) % 90 % 97 % (7) % Number of metered customers at end of period: Residential 3,634,423 3,609,924 1 % 3,634,423 3,609,924 1 % Commercial and Industrial 274,846 268,904 2 % 274,846 268,904 2 % Total 3,909,269 3,878,828 1 % 3,909,269 3,878,828 1 % 54 Table of Contents The following table provides variance explanations for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 as well as for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 by major income statement caption for CERC: Favorable (Unfavorable) Three Months Ended June 30, 2026 vs 2025 Six Months Ended June 30, 2026 vs 2025 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (20) $ (5) Gross receipts tax, offset in taxes other than income taxes below 2 5 Weather and usage (2) (20) Energy efficiency and other pass-through, offset in operation and maintenance below 4 8 Non-volumetric and miscellaneous revenue 6 7 Non-utility revenues 1 2 Customer growth 3 7 Customer rates and impact of the change in rate design 35 82 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — (148) Total $ 29 $ (62) Utility natural gas Cost of natural gas, offset in revenues above $ 20 $ 5 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 59 Total $ 20 $ 64 Operation and maintenance All other operations and maintenance expense, including bad debt expense $ (14) $ (16) Energy efficiency and other pass-through, offset in revenues above (4) (8) Contract services (4) (11) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 20 Labor and benefits 4 3 Corporate support services 2 3 Total $ (16) $ (9) Depreciation and amortization Ongoing additions to plant-in-service $ (17) $ (36) Amortization of regulatory assets (3) 2 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 14 Total $ (20) $ (20) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (2) $ (5) Incremental capital projects placed in service, and the impact of updated property tax rates (4) (6) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 (2) 6 Total $ (8) $ (5) Gain on sale Gain on sale of Louisiana and Mississippi natural gas LDC businesses $ — $ (52) Total $ — $ (52) Interest expense and other finance charges Changes in outstanding debt $ (13) $ (35) Other, primarily AFUDC and impacts of regulatory deferrals 8 10 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 — 10 Total $ (5) $ (15) Other income, net Other income, including AFUDC - Equity and affiliate interest income $ (6) $ (5) Total $ (6) $ (5) Income Tax Expense. For a discussion of effective tax rate per period, see Note 10 to the Interim Condensed Financial Statements 55 Table of Contents CERTAIN FACTORS AFFECTING FUTURE EARNINGS For information on other developments, factors and trends that may impact the Registrants’ future earnings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Part II, Item 7 and “Risk Factors” in Part I, Item 1A of the Registrants’ combined 2025 Form 10-K, and “Cautionary Statement Regarding Forward-Looking Information” in this combined Form 10-Q. LIQUIDITY AND CAPITAL RESOURCES Cash Flows The following table summarizes the Registrants’ cash flows by category for the period presented: Six Months Ended June 30, 2026 2025 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Cash provided by (used in): Operating activities $ 1,060 $ 460 $ 765 $ 970 $ 117 $ 1,025 Investing activities (2,527) (1,822) (809) (1,341) (881) 455 Financing activities 1,489 1,388 44 440 765 (1,482) Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the six months ended June 30, 2026 compared to the six months ended June 30, 2025: CenterPoint Energy Houston Electric CERC (in millions) Changes in net income after adjusting for non-cash items $ 306 $ 268 $ 65 Changes in working capital (192) 35 (157) Other non-current assets (121) 88 (233) Other non-current liabilities (9) (35) 35 Lower (higher) pension contribution 47 — (4) Other 59 (13) 34 $ 90 $ 343 $ (260) Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities for the six months ended June 30, 2026 compared to the six months ended June 30, 2025: CenterPoint Energy Houston Electric CERC (in millions) Lower cash payments for asset acquisitions $ 357 $ — $ — Net change in capital expenditures (401) (378) (171) Net change in notes receivable from affiliated companies — (550) 1 Lower cash proceeds from divestitures (1,219) — (1,219) Other 77 (13) 125 $ (1,186) $ (941) $ (1,264) 56 Table of Contents Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities for the six months ended June 30, 2026 compared to the six months ended June 30, 2025: CenterPoint Energy Houston Electric CERC (in millions) Net changes in commercial paper outstanding $ (1,558) $ — $ 201 Net changes in proceeds from issuances of Common Stock 165 — — Net changes in long-term debt and term loans outstanding, excluding commercial paper 2,465 975 973 Net changes in debt issuance costs (12) (11) — Net changes in short-term borrowings 3 — 3 Increased payment of dividends on Common Stock (15) — — Net change in notes payable to affiliated companies — (507) (291) Change in dividend to parent — 165 633 Other 1 1 7 $ 1,049 $ 623 $ 1,526 Future Sources and Uses of Cash The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, storm restoration costs, debt service requirements, tax payments, working capital needs and various regulatory actions. Future capital expenditures are expected to primarily relate to investments in infrastructure. These capital expenditures are anticipated to enhance the safety, reliability and resiliency of our systems and deliver consistent value for stakeholders across the Registrants’ jurisdictions. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for the remainder of 2026 include the following: CenterPoint Energy Houston Electric CERC (in millions) Estimated capital expenditures $ 4,088 $ 2,286 $ 1,343 Scheduled principal payments on Securitization Bonds 69 62 — Scheduled principal payments on debt instruments, excluding Securitization Bonds 1,317 300 — Expected contributions to pension plans and other post-retirement plans 46 — 1 The Registrants expect that anticipated cash needs for the remainder of 2026 will be met with available cash flow from operations, proceeds from the sale of our Ohio natural gas LDC business, contributions in aid of construction as well as cash flows from financing (such as issuances of debt securities and equity securities upon physical settlement of outstanding forward sale agreements and borrowings under credit facilities, commercial paper issuances or other sources). At this time, CenterPoint Energy does not anticipate the need for any sales of shares of Common Stock under the 2026 Equity Distribution Agreement in 2026. The issuance of securities in the capital markets and borrowings under additional credit facilities and term loans may not, however, be available on acceptable terms. The Registrants may, from time to time, redeem, repurchase or otherwise acquire their outstanding debt securities through open market purchases, tender offers or pursuant to the terms of such securities. Off-Balance Sheet Arrangements Other than Houston Electric’s general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy as discussed in Note 9 and guarantees as discussed in Note 11(c) to the Interim Condensed Financial Statements, the Registrants have no off-balance sheet arrangements. 57 Table of Contents Regulatory Matters TEEEF (CenterPoint Energy and Houston Electric) For information about TEEEF, see Note 6 to the Interim Condensed Financial Statements. Hurricane Beryl (CenterPoint Energy and Houston Electric) For additional information about the recovery of costs incurred in connection with Hurricane Beryl, see Note 6 to the Interim Condensed Financial Statements. Indiana Electric CPCN (CenterPoint Energy) PPAs On August 25, 2021, Indiana Electric filed with the IURC seeking approval to purchase 150 MW of solar power, under a 20-year PPA, from Origis, which is developing a solar project in Knox County, Indiana. On May 4, 2022, the IURC issued an order approving Indiana Electric to enter into the Knox County PPA. In March 2022, when the results of the MISO interconnection study were completed, Origis advised Indiana Electric that the costs to construct the solar project in Knox County, Indiana had increased largely due to escalating commodity and supply chain costs impacting manufacturers worldwide. In August 2022, Indiana Electric and Origis entered into an amended PPA, which reiterated the terms contained in the 2021 PPA with certain modifications. On February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date was delayed from 2024 to 2026. The facility became operational on February 27, 2026. The power purchase costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA. On May 1, 2024, Indiana Electric filed with the IURC seeking approval to purchase 147 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Knox County, Illinois. On November 6, 2024, the IURC approved the Knox County wind PPA, which provided for the recovery of the purchase power costs through the fuel adjustment clause proceedings over the term of the PPA. The facility was targeted to be in operation in late 2026, however construction was recently halted by the developer following the Department of War’s pause on approving the required mitigation plan, and it is uncertain, when, if at all, the project will become operational. F.B. Culley Unit 2 (CenterPoint Energy) While Indiana Electric’s 2025 IRP (similar to previous IRPs) preferred portfolios included the retirement of F.B. Culley Unit 2, a coal-fired generation unit, by the end of 2025, the U.S. Department of Energy issued emergency 202(c) orders (the “DOE Order”) in December 2025, March 2026 and June 2026 directing Indiana Electric to continue operating the unit through September 19, 2026. Indiana Electric has filed a complaint with the FERC to request creation of a cost recovery/cost allocation mechanism. On March 19, 2026, FERC directed MISO to adopt a tariff amendment that would authorize the F.B. Culley unit to recover costs across load-serving entities situated in MISO’s north and central local reliability zones, otherwise known as MISO North and Central. A separate filing will be made at a later date with the FERC to seek recovery of all costs incurred to comply with the U.S. Department of Energy’s emergency 202(c) orders. Indiana Electric has also filed an application with the IURC in Cause No. 46350 to recover any compliance costs associated with the emergency 202(c) orders that are not recovered through the FERC proceedings. On April 15, 2026, Indiana Electric filed a Motion to Intervene in the United States Court of Appeals for the D.C. Circuit in response to the Public Interest Organizations’ appeal of the December 2025 DOE Order. Indiana Electric intervened as the owner of F.B. Culley 2 that is the subject of the DOE Order representing Indiana Electric’s authority to recover the costs it has incurred to comply with the DOE Order. On May 8, 2026, the D.C. Circuit granted Indiana Electric’s motion to intervene and consolidated Indiana Electric’s case with the Public Interest Organizations’ appeal of the DOE emergency 202(c) order issued to Northern Indiana Public Service Company in December 2025 for its Schahfer plant. On June 29, 2026, the D.C. Circuit granted the U.S. Department of Energy’s unopposed motion to hold the consolidated appeals of the Culley and Schahfer DOE 202(c) orders in abeyance pending disposition of the People of the State of Michigan v. United States Department of Energy (the appeal of DOE’s 202(c) order issued to the Consumer Energy Company’s Campbell plant.) A modification to Indiana Electric’s wastewater discharge permit for F.B Culley Unit 2 has been proposed that would provide for the continued utilization of bottom ash transport water at the facility during the pendency of the DOE Order. The public comment period for the proposed modification closed on July 20, 2026, with a final agency decision expected later in the third quarter of 2026. On July 20, 2026, the Sierra Club and Environmental Law & Policy Center filed a petition with the United States Court of Appeals for the D.C. Circuit for review of FERC’s March 19, 2026 order related to the cost recovery/cost allocation mechanism and FERC’s subsequent procedural denial of the rehearing requests on the March 19th order. 58 Table of Contents Indiana Legislation (CenterPoint Energy) Indiana Electric is actively working to comply with legislation passed in 2026, particularly, the following pieces of legislation that became law in Indiana’s 124th General Assembly: Senate Enrolled Act 240 Surplus Interconnection Service (SIS) defines SIS as any portion of service that has not been used and is not reasonably expected to be needed; the use of which would result in the total amount of interconnection service at the point of interconnection remaining the same. The new law requires an electric utility to include an analysis of the potential for SIS to meet the immediate needs for capacity and energy at the utility-owned facilities in integrated resource plans. It also requires the IURC to consider whether a utility that has filed for approval of a certificate of public convenience and necessity has conducted a SIS analysis and whether the proposed construction will allow for the use of SIS. House Enrolled Act 1002, a multi-faceted law aimed at improving the affordability of electric rates, includes the following provisions: •beginning in 2026, require an electric utility to file a multi-year rate plan according to a prescribed schedule; •apply a customer affordability performance metric and a service restoration performance metric to each year of the multi-year rate plan and use such metric to provide financial rewards or penalties based on the electricity supplier’s measured performance of the metric; •require an electric utility to offer a low income customer assistance program by July 1, 2026 to be funded by at least 0.2% of jurisdictional revenues for residential customers and allow the utility to seek recovery of eligible program costs; •prohibit an electric utility from terminating service to any customer on a day forecasted by the National Weather Service to have a heat index of at least 95 degrees Fahrenheit; •modify the IURC’s authority related to use of emergency powers; •apply a levelized billing plan to residential customers who are eligible and have applied for the Low Income Housing Energy Assistance Program; and •require an electric utility to report certain residential customer data to the Office of the Utility Consumer Counselor on a quarterly basis. Pursuant to House Enrolled Act 1002 (HEA 1002), Indiana Electric is required to file a multi-year rate case in January 2028. On July 15, 2026, the IURC opened two investigations related to the implementation of the new multi-year rate plan (“MYRP”) framework established under HEA 1002. In Cause No. 46428, the IURC will examine potential risks and changes in risks to Indiana electric utilities and their customers resulting from implementation of MYRPs, including consideration of historical authorized-return frameworks and the establishment of a reasonable baseline for evaluating any changes in risk. In Cause No. 46429, the IURC will investigate cost recovery mechanisms within the MYRP framework, including the potential role of capital and expense trackers and the development of reasonable and quantifiable criteria governing their use. The IURC made all Indiana electric utilities respondents to both proceedings and scheduled technical conferences for August 7, 2026 to identify issues and establish procedural schedules. Indiana Electric is evaluating the orders and intends to participate in the proceedings. At this time, Indiana Electric cannot predict the outcome of either investigation or the potential impact, if any, that these proceedings may have on its future rates, cost recovery mechanisms, authorized returns, or financial condition. Texas Legislation (CenterPoint Energy, Houston Electric and CERC) The Registrants are evaluating the effects of certain legislation passed in 2025 and associated PUCT rulemaking projects, including the following pieces of legislation that became law during the 89th Texas Legislature: •House Bill 4384, effective June 20, 2025, allows LDCs to recover post in-service carry costs (PISCC) in GRIP filings. This allows LDCs to defer for future recovery as a regulatory asset PISCC, depreciation expense and ad valorem taxes associated with unrecovered gross plant. •Senate Bill 231, effective June 20, 2025, provides that, on or after the effective date, TDUs may only enter into, renew or extend leases for TEEEF units with a maximum generation capacity 5 or fewer MW and that are rapidly deployable, and that they may enter into leases without prior PUCT preapproval (as required by the TEEEF Rule) in the case of an emergency or if the lease includes a provision allowing for the alteration of the lease based on applicable PUCT orders or rules. •Senate Bill 1963, effective September 1, 2025, allows ERCOT utilities to securitize system restoration costs using a third-party government agency, which may allow for the debt to be off balance sheet and an abbreviated proceeding 59 Table of Contents timeline. This bill also lowered the system restoration costs threshold from $100 million to $50 million, provided the effectiveness tests are met. •Senate Bill 6, effective June 20, 2025, establishes a standardized process for connecting large-load customers within ERCOT in a manner designed to support business development in Texas while minimizing the potential for stranded infrastructure costs and maintaining system reliability. CSIA 3.0 (CenterPoint Energy) On June 2, 2026, CEI North and CEI South filed their petitions and cases-in-chief with the IURC requesting, among other things, approval of their seven-year plan for transmission, distribution, and storage improvements, pursuant to Ind. Code (TDSIC Plan) and their three-year compliance projects pursuant to Ind. Code (Compliance Projects). The request for the three-year Compliance Projects (2027-2029) was for an estimated $679 million (Indiana North) and $160 million (Indiana South), and the request for the seven-year Transmission, Distribution, Storage Improvement Charge (TDSIC) Plan (2027-2033) was for an estimated $902 million (Indiana North) and $211 million (Indiana South). OUCC and intervenors will file testimony and exhibits on or before August 26, 2026. Indiana North and Indiana South rebuttal testimony is due on or before September 18, 2026. Evidentiary hearings are scheduled for Indiana North on October 5, 2026, and for Indiana South on October 8, 2026. Rate Change Applications The Registrants are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Registrants are periodically involved in proceedings to adjust their capital tracking mechanisms (e.g., CSIA, DCRF, CEP, DRR, GRIP, TCOS, ECA, CECA and TDSIC), their decoupling mechanisms (e.g., decoupling and SRC), and their energy efficiency cost trackers (e.g., CIP, DSMA, EECRF, EEFC and EEFR). The table below reflects significant applications pending or completed since the Registrants’ combined 2025 Form 10-K was filed with the SEC through the date of the filing of this combined Form 10-Q: Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and Houston Electric (PUCT) TEEEF $ (24) April 2025 TBD TBD Seeks approval of: (1) the release of Houston Electric’s 15 large 32 MW TEEEF units to ERCOT at CPS Energy facilities to serve the greater San Antonio region until March 2027 unless terminated earlier pursuant to the provisions of the ERCOT Transaction; (2) a corresponding reduction to the capacity of the Houston Electric TEEEF fleet; and (3) a reduction and update to Houston Electric’s rider TEEEF rate to reflect the removal of the 15 large 32 MW TEEEF units from Houston Electric’s TEEEF fleet. Houston Electric will make no revenue or profit from ERCOT for the time period when the 15 large 32 MW TEEEF units are in the San Antonio area being dispatched by ERCOT. In November 2025, Houston Electric also proposed to remove the five medium 5.7 MW TEEEF units from its TEEEF fleet and remove the associated lease costs effective January 1, 2026. On June 26, 2026, Houston Electric filed a stipulation and agreement supporting removal of the 15 large units and 5 medium units effective May 1, 2025 and January 1, 2026, respectively, an agreed motion for interim rates effective August 15, 2026, settlement testimony, and agreed motion to admit evidence and remand the proceeding to the PUCT. On June 29, 2026, SOAH granted the requested motions and remanded the proceeding to the PUCT. If approved by the PUCT, the current revenue requirement will be reduced by $112 million. TEEEF N/A May 2025 March 2026 March 2026 Seeks authorization to lease small, 200 kW to 1,250 kW TEEEF units for 36 months in accordance with the TEEEF Rule. Among other things, the TEEEF Rule generally requires that a utility obtain preapproval prior to renewing or entering into a new lease of TEEEF units, with exceptions for emergency situations or if the lease includes a provision allowing for the alteration of the lease based on applicable PUCT orders or rules. Approval of Houston Electric’s request in this filing will have no cost impact on customers at this time, as cost determination will occur in a future proceeding. On March 12, 2026, the PUCT issued an order authorizing Houston Electric to enter into a lease for a combined approximately 20 MW of TEEEF capacity comprised of 36 small TEEEF units, each with a capacity range of 200 kW to 1,250 kW, for a term of 36 months. 60 Table of Contents Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information DCRF $ 108 February 2026 TBD TBD Based on the net change in distribution invested capital since its last base rate proceeding of approximately $2.2 billion for the period January 1, 2024 through December 31, 2025 for an incremental revenue increase of $108 million adjusted for load growth. In April 2026, a stipulation and settlement agreement was filed, reducing the revenue requirement by $6.2 million to reflect deferral of $52.3 million in investment related to certain system resiliency plan measures. For future DCRFs in 2026, 2027, and 2028, Houston Electric agreed to defer additional costs in proportion to the amount invested in certain resiliency measures as a percentage of the total estimated costs for those measures. On July 9, 2026, the PUCT issued an order that approved the DCRF adjustment but required Houston Electric to defer recovery for certain resiliency measures up front rather than proportionally as proposed in the settlement. On July 15, 2026, Houston Electric filed a compliance tariff for $101.4 million and requested rates with an expected implementation date of September 1, 2026. PUCT decision is due by August 3, 2026. TCOS $ 36 February 2026 April 2026 April 2026 Based on the net change in invested capital since its last TCOS proceeding of approximately $212 million for the period of July 1, 2025 through December 31, 2025, along with the inclusion of regulatory assets of approximately $10 million comprising certain system restoration operations and maintenance expenses and carrying costs associated with the May 2024 Storm Events and Hurricane Beryl. EECRF $ 16 June 2026 March 2027 TBD Requested $77 million which is comprised primarily of the following: 2027 program costs of $58 million; $2.4 million related to the under-recovery of 2025 program costs; the 2025 earned bonus of $16 million; and 2027 projected evaluation, measurement and verification costs of $0.6 million. DCRF $ 73 July 2026 TBD TBD Based on the net change in distribution capital since its last base rate proceeding of approximately $2.8 billion for the period January 1, 2024 through May 31, 2026, for an incremental revenue increase of $73 million adjusted for load growth compared to the compliance filing for the previous DCRF. CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission) GRIP $ 62 February 2026 June 2026 June 2026 Based on net change in invested capital of $394 million. CenterPoint Energy and CERC - Minnesota (MPUC) CIP Financial Incentive $ 7 May 2026 TBD TBD CIP Financial Incentive based on 2025 CIP program activity. CenterPoint Energy - Indiana South - Electric (IURC) TDSIC $ 2 February 2026 TBD TBD Requested an increase of $19.5 million to rate base, which reflects an approximately $2.1 million increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under recovery variance of $(1.8) million. CenterPoint Energy - Indiana South - Gas (IURC) CSIA $ 3 April 2026 TBD TBD Requested an increase of $26.7 million to rate base, which reflects an approximately $2.5 million increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under recovery variance of $2.5 million. The OUCC filed testimony on June 2, 2026. Indiana South’s rebuttal was filed on June 15, 2026. Reply briefs to proposed order were filed on July 15, 2026. CenterPoint Energy and CERC - Indiana North - Gas (IURC) CSIA $ 14 April 2026 TBD TBD Requested an increase of $121.9 million to rate base, which reflects an approximately $14.4 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under recovery variance of $9.2 million. The OUCC filed testimony on June 2, 2026. Indiana North’s rebuttal was filed on June 15, 2026. Reply briefs to proposed order were filed on July 15, 2026. CenterPoint Energy and CERC - Ohio - Gas (PUCO) CEP $ 12 March 2026 TBD TBD Requested an increase of $100.9 million to rate base for investments made in 2025, which reflects an $11.7 million annual increase in current revenues. A change in (over)/under-recovery variance of $(0.9) million is also included in rates. If necessary, an evidentiary hearing will be conducted on August 20, 2026. If a hearing is necessary and some or all of the parties enter into a stipulation resolving some or all issues raised in this proceeding, the stipulation and supporting testimony must be filed with the PUCO by August 13, 2026. DRR $ 10 May 2026 TBD TBD Requested an increase of $67 million to rate base for investments made in 2025, which reflects a $9.5 million annual increase in current revenues. A change in (over)/under-recovery variance of $($3.0) million annually is also included in rates. Staff filed comments on June 25, 2026, recommending approval of the DRR revenue requirement and proposed rates. OCC filed comments on June 26, 2026 indicating concerns with affordability and the pace of investments in the DRR. On July 10, 2026, CenterPoint Ohio filed a statement informing the PUCO the issues raised in comments have been resolved. (1)Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates. 61 Table of Contents GHG Emissions and Climate-Related Regulation and Compliance (CenterPoint Energy) The issue of climate change has received focus at the state, federal and international level, and there are trends and uncertainties relating to GHG emissions and climate-related regulations and compliance that affect the Registrants. On February 18, 2026, the US EPA rescinded the 2009 endangerment finding in relation to GHG standards for mobile sources. Uncertainties remain as to the effect of the rescission on the GHG standards for fossil fuel-fired power plants, which are similarly being challenged on judicial review, and the effects of the rescission on preemption of state law. Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain; nevertheless, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. CenterPoint Energy will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, CenterPoint Energy does not purchase carbon credits. In connection with its energy transition goals, CenterPoint Energy is expected to purchase carbon credits in the future; however, CenterPoint Energy does not currently expect the number of credits, or cost for those credits, to be material. Climate Risk Trends and Uncertainties There are climate risk trends and uncertainties that affect the Registrants. Changes in the U.S. presidential administration and significant expected increases in electric demand, as announced by organizations such as ERCOT and MISO, have shifted the energy landscape in the United States. This shift in federal domestic energy policy has resulted in uncertainty with respect to the scope and speed of future renewable generation infrastructure development and the role that existing renewable generation will play in support of the U.S. energy grid. The long-term impacts of this domestic energy policy shift are also uncertain, including with respect to impacts on the development of, and consequently the availability of, alternative energy sources (such as solar energy, including private solar, wind energy, microturbines, fuel cells, energy-efficient buildings and energy storage devices). Additionally, it is unclear whether, and if so how, the new domestic energy policy, including the potential suspension, revision or rescission of regulations restricting emissions (including methane emissions), and the repeal of the Endangerment Finding, will affect consumers’ and companies’ energy use, adoption of alternative energy sources or decisions to expand their facilities, including natural gas facilities. Other Matters Credit Facilities The Registrants may draw on their respective revolving credit facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop CenterPoint Energy’s and CERC’s commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to the Registrants’ revolving credit facilities, see Note 9 to the Interim Condensed Financial Statements. Based on the consolidated debt to capitalization covenant in the Registrants’ revolving credit facilities, the Registrants would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated approximately $4.0 billion as of June 30, 2026. As of July 22, 2026, the Registrants had the following revolving credit facilities and utilization of such facilities: Amount Utilized as of July 22, 2026 Registrant Size of Facility Loans Letters of Credit Commercial Paper Weighted Average Interest Rate Termination Date (in millions) CenterPoint Energy $ 2,400 $ — $ — $ — —% December 6, 2028 CenterPoint Energy (1) 250 — — — —% December 6, 2028 Houston Electric 300 — — — —% December 6, 2028 CERC 1,050 — — 13 3.79% December 6, 2028 Total $ 4,000 $ — $ — $ 13 (1)This credit facility was issued by SIGECO. The Registrants and SIGECO are currently in compliance with the various business and financial covenants in the four revolving credit facilities. 62 Table of Contents Debt Transactions For detailed information about the Registrants’ debt transactions to date in 2026, see Note 9 to the Interim Condensed Financial Statements. Securities Registered with the SEC On May 15, 2026, the Registrants filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on May 15, 2029. For information related to the Registrants’ debt issuances in 2026, see Note 9 to the Interim Condensed Financial Statements. For information related to shares of Common Stock sold or issued pursuant to the forward sale agreements and the 2026 Equity Distribution Agreement, see Note 15 to the Interim Condensed Financial Statements. Money Pool The Registrants participate in a money pool through which they and certain of their subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the CenterPoint Energy money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The net funding requirements of the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of CERC’s commercial paper. The table below summarizes CenterPoint Energy money pool activity by Registrant as of July 22, 2026: Weighted Average Interest Rate Houston Electric CERC (in millions) Money pool investments (borrowings) 3.67% $ 679 $ (432) Impact on Liquidity of a Downgrade in Credit Ratings The interest rate on borrowings under the credit facilities is based on the respective credit rating of each borrower. As of July 22, 2026, Moody’s, S&P and Fitch had assigned the following credit ratings to the borrowers: Moody’s S&P Fitch Registrant Borrower/Instrument Rating Outlook (1) Rating Outlook (2) Rating Outlook (3) CenterPoint Energy CenterPoint Energy Senior Unsecured Debt Baa2 Negative BBB Stable BBB Stable CenterPoint Energy Vectren Corp. Issuer Rating n/a n/a BBB+ Stable n/a n/a CenterPoint Energy SIGECO Senior Secured Debt A1 Stable A Stable n/a n/a Houston Electric Houston Electric Senior Secured Debt A2 Negative A Stable A Stable CERC CERC Corp. Senior Unsecured Debt A3 Stable BBB+ Stable A- Stable CERC Indiana Gas Senior Unsecured Debt n/a n/a BBB+ Stable n/a n/a (1)A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. (2)An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3)A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period. The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies. 63 Table of Contents A decline in credit ratings could increase borrowing costs under the Registrants’ revolving credit facilities. If the Registrants’ credit ratings had been downgraded one notch by S&P and Moody’s from the ratings that existed as of June 30, 2026, the impact on the borrowing costs under the four revolving credit facilities would have been insignificant. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas reportable segments. Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC might need to provide cash or other collateral of up to $232 million as of June 30, 2026. The amount of collateral will depend on seasonal variations in transportation levels. ZENS and Securities Related to ZENS (CenterPoint Energy) If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought CenterPoint Energy’s liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically be reversed when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year, and there could be a cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on June 30, 2026, deferred taxes of approximately $964 million would have been payable in 2026, subject to reduction on account of available net operating loss carryforwards and CAMT carryforwards. If all the ZENS-Related Securities had been sold on June 30, 2026, capital gains taxes of approximately $49 million would have been payable in 2026 based on 2026 tax rates in effect. As of June 30, 2026, CenterPoint Energy had both net operating loss and CAMT carryforwards available from its filed 2024 federal income tax return that can be applied to largely offset the cash outflow that would result from a retirement or exchange of the ZENS. For additional information about ZENS, see Note 8 to the Interim Condensed Financial Statements. Cross Defaults Under the Registrants’ respective revolving credit facilities, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by the borrower or any of their respective significant subsidiaries will cause a default under such borrower’s respective credit facility or term loan agreement. Under SIGECO’s revolving credit facility, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specific types of obligations (including guarantees) exceeding $75 million by SIGECO or any of its significant subsidiaries will cause a default under SIGECO’s credit facility. A default by CenterPoint Energy would not trigger a default under its subsidiaries’ debt instruments or revolving credit facilities. Possible Acquisitions, Divestitures and Joint Ventures From time to time, the Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. The Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to the Registrants at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions. As announced in July 2026, CenterPoint Energy has increased its planned capital expenditures in its Electric and Natural Gas businesses pursuant to its updated 10-year capital plan, which calls for investment of at least $66.7 billion through 2035, and CenterPoint Energy may continue to increase such planned capital investments in the future. The Registrants may continue to explore asset sales as a means to efficiently finance a portion of their increased capital expenditures in the future, subject to the considerations listed above. For further information, see Note 3 to the Interim Condensed Financial Statements. 64 Table of Contents On October 20, 2025, CenterPoint Energy, through CERC Corp., entered into the Ohio Securities Purchase Agreement to sell all of the issued and outstanding equity interests in CEOH for total consideration of approximately $2.62 billion, subject to adjustment as set forth in the Ohio Securities Purchase Agreement. The transaction is expected to close in the fourth quarter of 2026, subject to the satisfaction of customary closing conditions. For further information, see Note 3 to the Interim Condensed Financial Statements. Collection of Receivables from REPs (CenterPoint Energy and Houston Electric) Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, weather events such as the February 2021 Winter Storm Event, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows. In the event of a REP default, Houston Electric’s tariff provides a number of remedies, including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity. Other Factors that Could Affect Cash Requirements In addition to the above factors, the Registrants’ liquidity and capital resources could also be negatively affected by: •cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas reportable segment; •acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased natural gas prices, and concentration of natural gas suppliers (CenterPoint Energy and CERC); •increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC); •increased costs of certain goods, materials or services due to, among other things, supply chain disruptions, inflation, labor shortages, scarcity of materials and changes in U.S. or foreign trade policy (including tariffs or other trade actions); •increases in interest expense in connection with debt refinancings and borrowings under credit facilities or term loans or the use of alternative sources of financings, including financings due to the May 2024 Storm Events and Hurricane Beryl; •various legislative, executive or regulatory actions at the federal, state and local levels, including actions in response to Hurricane Beryl and actions pertaining to U.S. or foreign trade policy (including tariffs or other trade actions) or other geopolitical matters; •incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy); •the timing and outcome of rate actions regarding our recovery of costs and ability to make a reasonable return on investment; •the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric; •slower customer payments and increased write-offs of receivables due to higher natural gas prices, changing economic conditions, public health threats or severe weather events, such as the May 2024 Storm Events and Hurricane Beryl; •the satisfaction of any obligations pursuant to guarantees; •the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl; •contributions to pension and postretirement benefit plans; •recovery of any losses under applicable insurance policies; •restoration costs and revenue losses resulting from future natural disasters such as hurricanes or other severe weather events and the timing of and amounts sought for recovery of such restoration costs; •the required return to customers of contributions in aid of construction or financial security in connection with proposed large-load interconnection projects; and 65 Table of Contents •various other risks identified in “Risk Factors” in Part I, Item 1A of the Registrants’ combined 2025 Form 10-K, which are incorporated herein by reference, in Part II, Item 1A of this combined Form 10-Q, and in other reports that the Registrants file from time to time with the SEC. Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money Certain provisions in certain note purchase agreements relating to debt issued by CERC have the effect of restricting the amount of secured debt issued by CERC and debt issued by subsidiaries of CERC Corp. Additionally, Houston Electric and SIGECO are limited in the amount of mortgage bonds they can issue by the General Mortgage and SIGECO’s mortgage indenture, respectively. For information about the total debt to capitalization financial covenants in the Registrants’ and SIGECO’s revolving credit facilities, see Note 9 to the Interim Condensed Financial Statements. CRITICAL ACCOUNTING POLICIES A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. Our critical accounting policies that we deemed the most material in nature were reported in our combined 2025 Form 10-K. There have been no material changes with regard to these critical accounting policies.