CENTERPOINT ENERGY INC (CNP)

Item 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

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

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.

Updated 10-Year Capital Plan. On February 19, 2026, CenterPoint Energy announced an increase in the 10-year capital plan of $500 million to reflect total capital expenditures of approximately $65.5 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.

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, 2026. On April 10, 2026, Houston Electric requested continued abatement until April 24, 2026 due to continued settlement discussions. 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.

42

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 months ended March 31, 2026 and 2025 was as follows:

(1)Includes unallocated corporate costs, interest income and interest expense and intercompany eliminations.

Three months ended March 31, 2026 compared to three months ended March 31, 2025

Net income increased $19 million primarily due to the following items:

•an increase in net income of $32 million for the Electric reportable segment, as further discussed below;

•an increase in net income of $22 million for the Natural Gas reportable segment, as further discussed below; and

•an increase in net loss of $35 million for the Corporate and Other reportable segment, primarily due to the impact of accrued income tax expense offset in other segments.

Income Tax Expense. For a discussion of effective tax rate per period, see Note 10 to the Interim Condensed Financial Statements.

43

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:

44

Table of Contents

The following table provides variance explanations for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 by major income statement caption for CenterPoint Energy’s Electric reportable segment:

Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 10 to the Interim Condensed Financial Statements.

45

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:

[[GREPCENT_TABLE]]
[["","Three Months Ended March 31,"],["","2026","","2025","","Favorable (Unfavorable)"],["","(in millions, except operating statistics)"],["Revenues","$","1,765","","","$","1,853","","","$","(88)"],["Expenses:"],["Utility natural gas and fuel","890","","","933","","","43"],["Non-utility cost of revenues, including natural gas","1","","","1","","","\u2014"],["Operation and maintenance","258","","","265","","","7"],["Depreciation and amortization","148","","","147","","","(1)"],["Taxes other than income taxes","71","","","74","","","3"],["Total expenses","1,

[Excerpt truncated for page length; source filing is linked above.]

Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following combined discussion and analysis should be read in combination with the consolidated financial statements included in Item 8 herein. 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-K, 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.

OVERVIEW

Background

CenterPoint Energy is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution systems. For a detailed description of CenterPoint Energy’s operating subsidiaries, see Note 1 to the consolidated financial statements.

Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy, which provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas Gulf Coast area that includes the city of Houston.

50

CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, which (i) directly owns and operates natural gas distribution systems in Minnesota and Texas, (ii) indirectly, through Indiana Gas and CEOH, owns and operates natural gas distribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP.

On October 20, 2025, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Ohio Securities Purchase Agreement to sell all of the issued and outstanding equity interests in CEOH. 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 4 to the consolidated financial statements.

Reportable Segments

We discuss our operating results on a consolidated basis and individually for each of our reportable segments. We are first and foremost an energy delivery company and it is our intention to remain focused on these regulated segments. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject, among other factors.

Below is a summary of CenterPoint Energy’s reportable segments as of December 31, 2025. For a detailed description of each reportable segment, as well as the assets included in each reportable segment, see Part I, Item 1. Business and Item 2. Properties.

•The Electric reportable segment consisted of electric transmission and distribution services in the Texas Gulf Coast area in the ERCOT region and electric transmission and distribution services primarily to southwestern Indiana and includes power generation and wholesale power operations in the MISO region.

•The Natural Gas reportable segment consisted of (i) intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial and industrial customers in Indiana, Minnesota, Ohio and Texas; (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; (iii) residential appliance repair and maintenance services along with HVAC equipment sales to customers in Minnesota; and (iv) home repair protection plans to natural gas customers in Indiana, Ohio and Texas through a third party. The Louisiana and Mississippi natural gas LDC businesses were included in the Natural Gas reportable segment through March 31, 2025. See Note 4 for additional detail.

•The Corporate and Other reportable segment consisted of (i) energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group; (ii) corporate support operations that support all of CenterPoint Energy’s business operations; and (iii) office buildings and other real estate used for business operations.

Houston Electric and CERC each consist of a single reportable segment.

EXECUTIVE SUMMARY

We expect our businesses to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Factors Influencing Our Businesses and Industry Trends

We are an energy delivery company with electric transmission, distribution and generation operations and natural gas distribution operations that serve more than seven million metered customers across four states. The majority of our revenues are generated from the transmission and delivery of electricity and the sale of natural gas by our subsidiaries.

We continue to execute on our strategic goals for our businesses that were set in September 2025. Pursuant to this business strategy and in light of the nature of our businesses, significant capital investments are reflected in our new 10-year capital plan. In September 2025, we announced our new 10-year capital plan to invest $65 billion from 2026 through 2035, inclusive of a $2 billion increase in previously planned capital expenditures through 2030, and in February 2026, we announced an additional increase to reflect total expenditures of approximately $65.5 billion. Our 10-year capital plan is intended to advance economic

51

growth, improve the experience of our customers through enhancing the safety, reliability and resiliency of our systems and deliver consistent value for stakeholders across the jurisdictions in which we operate. These investments are not only intended to meet our customers’ current needs, but are also in anticipation of future organic growth from a diverse set of economic drivers. This organic growth is anticipated to result in rapid load growth in our service territories (as further discussed below). To fund these capital investments, we rely on internally-generated cash, borrowings under our credit facilities, proceeds from commercial paper, cash proceeds from strategic transactions (such as our Energy Systems Group divestiture in 2023, the sale of our Louisiana and Mississippi natural gas LDC businesses in 2025 and the announced sale of our Ohio natural gas LDC business, which is expected to close in the fourth quarter of 2026) and issuances of equity and debt securities in the capital markets, including the issuance of non-recourse system restoration bonds at Houston Electric to recover costs incurred primarily during the year ended December 31, 2024 due to the May 2024 Storm Events, as well as Hurricane Beryl and other significant storms.

We strive to maintain investment grade ratings for our debt securities to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would result in an increase in our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets along with high or rising interest rates can also affect the availability of external financing on terms we consider attractive. In those circumstances, we may not be able to obtain certain types of external financing or may be required to accept terms less favorable than we would otherwise accept which, among other things, would negatively impact our ability to finance our capital plan. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt.

Approximately 85% of our rate base has been subject to a rate case since the beginning of 2023, which supports clarity and stability through 2029 with final orders improving enterprise weighted average returns on equity. Additionally, approximately 85% of CenterPoint Energy’s projected consolidated investments are expected to be recovered through interim capital recovery trackers or rate cases based on a forward test year. For additional detail, see “—Liquidity and Capital Resources —Regulatory Matters” below.

To assess our financial performance, our management primarily monitors the recovery of costs and return on investments by evaluating net income and capital expenditures, among other metrics, from our regulated service territories within our reportable segments. Within these broader financial measures, we monitor margins, natural gas and fuel costs, interest expense, capital spend, working capital requirements and operation and maintenance expense, among other significant metrics. In addition to these financial measures, we also monitor a number of variables that management considers important to gauge the performance of our reportable segments, including the number of customers, throughput, commodity prices, heating and cooling degree days, safety factors, system reliability and customer satisfaction.

CenterPoint Energy and CERC have weather normalization or other rate mechanisms that largely mitigate the impact of weather on their natural gas distribution businesses in Indiana, Minnesota and Ohio, as applicable. CenterPoint Energy’s and CERC’s natural gas distribution businesses in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms. As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s natural gas distribution business’ results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories.

Management anticipates significant growth in electric demand over the next decade, especially in our Houston Electric territory where we forecast a nearly 50% increase in peak electric load demand to over 30 GW by 2029 and the demand nearly doubling by the mid 2030s, as compared to 2024. It is expected that the significant forecasted growth in this service territory will be driven by a diverse set of economic drivers, including data centers, energy refining and exports, advanced manufacturing and logistics. Management additionally believes that there are increased electric demand opportunities in our Indiana Electric jurisdiction; accordingly, Indiana Electric’s 2025 IRP included a large load scenario with a corresponding alternative preferred portfolio. Additionally, management expects residential meter growth for Houston Electric to remain in line with long-term trends at approximately 2% annually. As discussed above, a significant portion of the planned investments in our new 10-year capital plan are intended to support this growth. There is significant uncertainty with respect to the forecasted load growth and our ability to capitalize on the opportunities presented by these developments. For more information regarding such risks, see Part I, Item 1A. “Risk Factors — General and Other Risks — We are exposed to risks related to changes in demand and energy consumption...” Typical customer growth in the jurisdictions served by the Natural Gas reportable segment is approximately 1% annually. Management expects residential meter growth for CERC to remain in line with long-term trends at approximately 1% annually. Nevertheless, this expected growth may be partially offset by adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, which may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities. Long-term national trends indicate residential customers have reduced their energy consumption, which could adversely affect

52

our results. To the extent population growth is affected by lower energy prices and there is financial pressure on some of our customers who operate within the energy industry, there may be an impact on the growth rate of our customer base and overall demand for our services.

Macroeconomic and geopolitical developments, including high rates of inflation, supply chain disruptions, labor market constraints, tariffs, high interest rates, general economic slowdown and escalating global conflicts can impact our business, financial condition, results of operations and cash flow, including adversely impacting our ability to execute on our 10-year capital plan. Inflation and high interest rates have contributed, and may continue to contribute, to increased prices for materials and services experienced by us and other companies in our industry. Further, the global supply chain has experienced and may continue to experience significant disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and policy instability, tariffs and other changes in U.S. and foreign trade policy, changes in laws (including tax laws), executive orders, labor shortages, resource availability, long lead times, manufacturer production limitations, delivery delays, inflation, severe weather events and disruptions to internal or international shipping, including as a result of armed conflicts. We have also faced, and may continue to face, a shortage of experienced and qualified personnel in certain positions, which has resulted in increased competition for skilled labor and wage inflation. Additionally, increased demand for materials necessary for our business has resulted, and may continue to result, in greater competition for and scarcity of such materials. In 2025 and 2026, the U.S. government threatened, announced and, in certain cases, rescinded, tariffs on several foreign jurisdictions and imports (including steel) into the United States, which led, and may continue to lead, to the imposition of retaliatory tariffs and other measures taken by foreign jurisdictions. There is significant uncertainty as to the scope and durability of existing and future tariff measures, as well as the ultimate effects of the tariffs on economic conditions. These macroeconomic and geopolitical developments have adversely impacted the utility industry, and like many of our peers, we have experienced disruptions to our supply chain, as well as increased prices and scarcity of resources and labor, and we may continue to experience this in the future. These developments have impacted our financial results for the year ended December 31, 2025. We have taken actions across multiple vectors to reduce the impact of such developments on our results of operations, but if such conditions continue, they could negatively impact our ability to procure materials, supplies (such as natural gas) or services necessary for our business and 10-year capital plan at a reasonable cost in a timely manner, result in project cancellations or scope changes, delays, cost overruns, and under-recovery of costs and challenges to our ability to remain in compliance with applicable laws, regulations and policies, which could adversely affect our business, financial condition, results of operations and cash flows. For more information regarding such risk, see Part I, Item 1A. “Risk Factors — Risk Factors Affecting Financial, Economic and Market Risks — Disruptions to the global supply chain...” and “— Changes in U.S. or foreign trade policies.”

The utility industry has experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments. As noted above, we are making, and plan to continue to make, significant capital investments in our service territories under our 10-year capital plan to help operate and maintain safer, more reliable and growing electric and natural gas systems and support the electric demand growth that management is forecasting over the next decade. Rising costs and investments and the upward trend in spending are likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. Increased rates and impacts on customer bills or the perceived potential for such impacts, particularly in the current economic environment, has caused and could continue to cause customer affordability concerns, resistance from customers and other stakeholders and increased political, regulatory, community and other scrutiny and pressures. For example, in consideration of customer affordability concerns, Indiana Electric cancelled nearly $1 billion in renewable energy generation projects in 2025. These matters could impact our ability to execute our 10-year capital plan, result in adverse ratemaking and cost recovery determinations, increased financing needs and otherwise adversely affect our business, financial condition, results of operations and cash flows. For more information regarding such risk, see Part I, Item 1A. “Risk Factors.”

Significant Events

Updated 10-Year Capital Plan. On September 29, 2025, CenterPoint Energy announced a new 10-year capital plan to invest $65 billion from 2026 through 2035, inclusive of a $2 billion increase in previously planned capital expenditures through 2030. On February 19, 2026, CenterPoint Energy announced an additional increase of $500 million to reflect total capital expenditures of approximately $65.5 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.

Treasury Notice 2026-7. On February 18, 2026, Treasury Notice 2026-7 was issued. This notice clarifies the computation of AFSI by including an adjustment to deduct certain repair and maintenance costs that are capitalized in the applicable financial statement. While CenterPoint Energy is still evaluating this guidance, it expects a prospective reduction to its annual CAMT liability. Additionally, CenterPoint Energy expects to be able to amend prior year tax returns to claim a refund of CAMT paid.

53

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 release its five medium (5.7 MW) TEEEF units and to remove the associated lease costs from its rates effective January 1, 2026. On February 13, 2026, Houston Electric requested continued abatement until February 27, 2026 due to continued settlement discussions. For additional information, see Note 7 to the consolidated financial statements.

Debt Transactions. In 2025, CenterPoint Energy issued or borrowed a combined $3.7 billion of new debt, including: (i) SIGECO’s issuance of $515 million aggregate principal amount of its first mortgage bonds; (ii) Houston Electric’s issuance of $1.1 billion aggregate principal amount of its general mortgage bonds; (iii) Restoration Bond Company II’s issuance of approximately $401.5 million aggregate principal amount of its securitization bonds; (iv) CenterPoint Energy’s issuance of $1.0 billion aggregate principal amount of its convertible senior notes due 2028; and (v) CenterPoint Energy’s issuance of $700 million aggregate principal amount of its junior subordinated notes. During 2025, CenterPoint Energy repaid or redeemed a combined $61 million of outstanding debt, including $41 million of SIGECO’s first mortgage bonds and $20 million of Indiana Gas’s senior notes. In addition, CenterPoint Energy repurchased a combined of approximately $1.5 billion of outstanding debt in connection with settlement of its tender offers, including: (i) approximately $963 million of its senior notes; (ii) approximately $415 million of CERC’s senior notes; and (iii) approximately $234 million of Houston Electric’s general mortgage bonds. For further information about debt transactions in 2025, see Note 12 to the consolidated financial statements. In January 2026, CERC Corp. entered into a delayed draw term loan agreement pursuant to which the banks party thereto have committed to provide term loans in an aggregate principal amount of up to $800 million by March 30, 2026 in up to three separate borrowings, subject to the satisfaction or waiver of certain customary conditions. If not fully utilized, the term loan commitments expire on March 31, 2026. CERC Corp. borrowed $500 million on January 20, 2026, and expects to borrow the remaining $300 million during the first quarter of 2026. For further information, see Note 20 to the consolidated financial statements.

Assets Held for Sale. On October 20, 2025, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Ohio Securities Purchase Agreement, pursuant to which CERC Corp. has agreed to sell all of the issued and outstanding equity interests in CEOH. The purchase price is $2.62 billion, which is comprised of the following: (i) $1.42 billion in cash payable to CERC Corp. upon closing of the transaction, subject to adjustments as set forth in the Ohio Securities Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing of the transaction; and (ii) a 364-day seller promissory note, in the original principal amount of $1.2 billion, to be issued by NFGC at the closing of the transaction and payable to CERC Corp. as provided by the terms and conditions of the Seller Note Agreement. The transaction is not subject to a financing condition and is expected to close in the fourth quarter of 2026, subject to satisfaction of customary closing conditions. As of December 31, 2025, the assets included approximately 6,000 miles of transmission and distribution pipeline in Ohio serving approximately 337,000 metered customers. CEOH is reflected in CenterPoint Energy’s Natural Gas reportable segment and CERC’s single reportable segment, as applicable. For further information, see Note 4 to the consolidated financial statements.

CenterPoint Energy Board Leadership Structure Changes. On October 8, 2025, the Board unanimously appointed Jason P. Wells, Chief Executive Officer and President of CenterPoint Energy, to serve as Chair of the Board, effective immediately. Mr. Wells has served as a director on the Board since January 5, 2024. In addition, the Board approved the creation of a Lead Independent Director of the Board position and the independent directors of the Board unanimously appointed independent director Christopher H. Franklin to serve as the Lead Independent Director of the Board, effective immediately.

CenterPoint Energy Appointment of Chief Operating Officer. On July 21, 2025, CenterPoint Energy announced the appointment of Jesus Soto, Jr. to the position of Executive Vice President and Chief Operating Officer of CenterPoint Energy, effective August 11, 2025.

OBBBA and Executive Order 14315. On July 4, 2025, the OBBBA was signed into law. The OBBBA includes significant provisions, such as the permanent extension of certain expiring provisions of the TCJA and numerous changes to the energy tax credits initially introduced and expanded under the IRA. The legislation has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. Additionally, on July 7, 2025, President Trump issued Executive Order 14315, which relates to the implementation of such changes to energy tax credits. The Registrants have assessed the potential effects of the OBBBA and Executive Order 14315 and concluded that neither is expected to have a material impact on their

54

future financial results because the Registrants have limited generation activities qualifying for tax credits under the IRA. The Registrants will consider the impacts of the OBBBA and Executive Order 14315, as well as related guidance, on any future generation projects, including any BTAs or PPAs, as applicable.

Equity Transactions. In April 2025, Centerpoint Energy entered into forward sales agreements pursuant to the Equity Distribution Agreement with certain of the ATM Forward Purchasers. In May 2025, CenterPoint Energy entered into separate forward sale agreements with certain financial institutions. For further information about forward sales in 2025, see Note 11 to the consolidated financial statements.

Regulatory Proceedings. In 2024, Houston Electric filed an Application for Determination of System Restoration Costs and a Financing Order with the PUCT for the May 2024 Storm Events, which were settled in 2025. In 2025, Houston Electric filed an Application for Determination of System Restoration Costs and a Financing Order with the PUCT for Hurricane Beryl and subsequent storm events, which were settled in 2025. For further information, see Note 7 to the consolidated financial statements. For information related to our pending and completed regulatory proceedings in 2025 and to date in 2026, see “—Liquidity and Capital Resources —Regulatory Matters” below.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors that apply to all Registrants unless otherwise indicated including:

•The business strategies and strategic initiatives, restructurings, joint ventures and acquisitions or dispositions of assets or businesses involving us or our industry, including the ability to successfully complete such strategies, initiatives, transactions or plans on the timelines we expect or at all, such as the announced sale of our Ohio natural gas LDC business, which we cannot assure will have the anticipated benefits to us;

•industrial, commercial and residential growth in our service territories and changes in market demand and energy consumption, including in relation to the expansion of data centers (associated with, among other things, increasing demand for AI), energy refining and exports, advanced manufacturing and logistics, as well as the effects of energy efficiency measures, technological advances and demographic patterns, and our ability to appropriately estimate/forecast and effectively manage such demand and the business opportunities relating to such matters;

•our ability to fund and invest planned capital and the timely recovery of our investments, including the timing of and amounts sought for those related to our 10-year capital plan;

•our ability to execute and complete our planned capital projects and programs, including those within our 10-year capital plan, in a timely and cost-effective manner and within budget, obtain the anticipated benefits of such projects, and manage costs and impacts of such projects on customer affordability;

•our ability to successfully construct, operate, repair, maintain, replace and restart electric generating facilities, natural gas facilities, TEEEF and electric transmission facilities, as applicable, including in the event of an outage and in relation to complying with applicable environmental, reliability and safety standards;

•timely and appropriate rate actions that allow and authorize timely recovery of costs and a reasonable return on investment, including the timing of and amounts sought for recovery of Houston Electric’s applicable TEEEF leases and restoration costs relating to, among other things, Hurricane Beryl, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings or interim rate mechanisms;

•the timing and success of, and our ability to obtain approval for matters relating to, Houston Electric’s release of its large TEEEF units to the San Antonio area, proposed release of its medium TEEEF units, reduction of its TEEEF fleet capacity and reduction of rates to reflect the removal of the large and medium TEEEF units from Houston Electric’s TEEEF fleet, as well as Houston Electric’s ability to complete one or more other future transactions involving the large and medium TEEEF units on acceptable terms and conditions within the anticipated timeframe;

•economic conditions in regional and national markets, including economic uncertainty and volatility, potential for recession, changes to and increases in inflation and interest rates, and their effect on sales, prices and costs;

•severe weather events, natural disasters and other climate-related impacts, including the impact of severe weather events on operations, capital, legislation and/or regulations, such as seen in connection with the February 2021 Winter Storm Event, the May 2024 Storm Events and Hurricane Beryl;

•volatility in the markets for natural gas as a result of, among other factors, inflation, adverse weather conditions, supply and demand changes, availability of competitively priced alternative energy sources, political and geopolitical instability, commodity production levels and storage capacity, energy and environmental legislation and regulation and economic and financial market conditions;

55

•non-payment for our services due to financial distress of our customers and the ability of our customers, including REPs, to satisfy their obligations to CenterPoint Energy, Houston Electric and CERC, and the negative impact on such ability related to adverse economic conditions and severe weather events;

•public health threats, and their effect on our operations, business and financial condition, our industries and the communities we serve, U.S. and world financial markets and supply chains, potential regulatory actions and changes in customer and stakeholder behavior relating thereto;

•federal, state and local legislative, executive and regulatory actions or developments affecting various aspects of our businesses, including, among others, any actions resulting from Hurricane Beryl, energy deregulation or re-regulation, pipeline integrity and safety, actions relating to our facilities and changes in regulation, legislation and governmental action pertaining to the utility model, trade (including tariffs, bans, retaliatory trade measures taken against the United States or related governmental action), the implementation of budget and spending cuts to federal government agencies and programs, effects of government shutdowns, policies incentivizing or disincentivizing the development or utilization of alternative sources of generation (including distributed generation), health care, finance and actions regarding the rates charged by our regulated businesses;

•disruptions to the global supply chain, inflation, labor shortages and scarcity of certain materials, including as a result of changes in U.S. and foreign trade policy, geopolitical and economic uncertainty, regulatory and policy instability, severe weather and other catastrophic events, changes in laws, executive orders, legislation and other governmental action, increased competition for skilled labor and increases in demand for electricity, that could prevent CenterPoint Energy from securing the resources and labor needed to, among other things, fully execute on its strategy and 10-year capital plan, and otherwise impact the affordability of our rates for our customers;

•operations and maintenance costs, our ability to control such costs and cost-related impacts on the affordability of our rates for our customers;

•our ability to timely obtain and maintain necessary licenses, permits, easements and approvals from local, federal and other regulatory authorities on acceptable terms and resolve third-party challenges to such licenses, permits or approvals as applicable;

•direct or indirect effects on our facilities, resources, operations, reputation and financial condition resulting from terrorism, vandalism, cyberattacks or intrusions, data security breaches or other security incidents, threats or attempts to disrupt our businesses or the businesses of supply chain stakeholders (including by foreign actors), or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, derecho events, ice storms and other severe weather events, wildfires, pandemic health events, geopolitical conflict, civil unrest or other occurrences;

•the impact of negative opinions of us or our utility services that our customers, investors, legislators, regulators, creditors, rating agencies or other stakeholders may have or develop, which could result from a variety of factors, including actual or perceived failures in system reliability and safety, the speed of our response to service interruptions, rates and customer affordability, our ability to successfully execute our capital plan, media coverage and actions by third parties;

•damages to our network, facilities and systems, including as a result of wildfires, as well as to third-party property resulting in outages or shortages in our service territories, and losses in excess of insurance liability coverage;

•tax legislation and guidance and any changes in tax laws under the current or future administrations, including any further changes to or clarification of the IRA or the OBBBA, and any potential changes to tax rates, CAMT imposed, tax credits and/or interest deductibility, as well as uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;

•our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;

•actions by credit rating agencies, including any potential downgrades to credit ratings;

•local, state and federal legislative, executive and regulatory actions or developments relating to the environment, including, among others, those related to global climate risk, air emissions, GHG emissions, carbon emissions, wastewater discharges and the handling and disposal of CCR that could impact operations, cost recovery of generation plant costs and related assets, and CenterPoint Energy’s energy transition goals;

•the impact of unplanned facility outages or other closures;

•the sufficiency of our insurance coverage, including availability, cost, coverage and terms and ability to recover claims;

•impacts from CenterPoint Energy’s pension and postretirement benefit plans, such as the investment performance and increases to net periodic costs as a result of plan settlements and changes in assumptions, including discount rates;

•changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation;

56

•commercial bank and financial market conditions, including disruptions in the banking industry, our access to capital, the cost of such capital, the results of our financing and refinancing efforts, including availability of funds in the capital markets, and impacts on our vendors, customers and suppliers;

•inability of various counterparties to meet their obligations to us;

•the extent and effectiveness of our risk management activities;

•timely and appropriate regulatory actions, which include actions allowing requested securitization for any hurricanes or other severe weather events, such as Hurricane Beryl, or natural disasters or other amounts sought for recovery of costs, including stranded coal-fired generation asset costs;

•our ability to attract, effectively transition, motivate and retain an appropriately qualified workforce, identify and develop top talent to succeed management and maintain good labor relations;

•changes in technology, including with respect to efficient battery storage or the emergence or growth of new, developing or alternative sources of generation, and their adoption by consumers, and our ability to anticipate, adapt to and implement technological changes;

•advances in AI and our success in timely adopting, developing and deploying AI;

•the timing and outcome of any audits, disputes and other proceedings related to taxes;

•the recording of impairment charges;

•political and economic developments and actions, including energy and environmental policies under the current administration;

•CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including energy transition goals and operations and maintenance expenditure goals;

•the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl;

•the effect of changes in and application of accounting standards and pronouncements; and

•other factors discussed in “Risk Factors” in Part I, Item 1A of this report and in other reports that the Registrants file from time to time with the SEC.

57

CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS

CenterPoint Energy’s results of operations are affected by seasonal fluctuations in the demand for electricity and natural gas. CenterPoint Energy’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates its subsidiaries charge, debt service costs, income tax expense, its subsidiaries ability to collect receivables from REPs and customers and its ability to recover its regulatory assets. For information regarding factors that may affect the future results of our consolidated operations, see “Risk Factors” in Part I, Item 1A of this report.

Net income (loss) available to common shareholders was as follows for the periods presented:

(1)Includes results of operations from Louisiana and Mississippi natural gas LDC businesses through the date of the sale on March 31, 2025.

(2)Includes energy performance contracting and sustainable infrastructure services through Energy Systems Group through the date of sale on June 30, 2023, unallocated corporate costs, interest income and interest expense, intercompany eliminations and the reduction of income allocated to preferred shareholders through September 1, 2023, the date of the redemption of all of the outstanding shares of the Series A Preferred Stock.

2025 Compared to 2024

Net income available to common shareholders increased $33 million primarily due to the following items:

•an increase in income available to common shareholders of $34 million for the Electric reportable segment, as further discussed below;

•an increase in income available to common shareholders of $4 million for the Natural Gas reportable segment, as further discussed below; and

•a decrease in income available to common shareholders of $5 million for the Corporate and Other reportable segment, primarily due to increased borrowing costs of approximately $37 million, offset by a $21 million gain on early extinguishment of debt using proceeds from the divestiture of the Louisiana and Mississippi natural gas LDCs, and a $20 million gain on early extinguishment of debt associated with the October 2025 tender offer, which is further discussed in Note 12 to the consolidated financial statements. The remaining variance is primarily driven by an increase in other corporate expenses, including expenses associated with proposed divestitures.

2024 Compared to 2023

Net income available to common shareholders increased $152 million primarily due to the following items:

•an increase in income available to common shareholders of $17 million for the Electric reportable segment, as further discussed below;

•an increase in income available to common shareholders of $33 million for the Natural Gas reportable segment, as further discussed below; and

•an increase in income available to common shareholders of $102 million for the Corporate and Other reportable segment, primarily due to $50 million of income allocated to holders of Series A Preferred Stock in 2023 prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023 as discussed in Note 11 to the consolidated financial statements, a loss on sale of $13 million and current tax expense of $32 million related to the divestiture of Energy Systems Group recorded in 2023 further discussed in Note 4 to the consolidated financial statements, $19 million due to remeasurement of deferred income tax balances recorded during 2023, as well as $8 million due to lower state income taxes. The remaining variance is due largely to an increase in borrowing costs.

Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements.

58

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 separated into two reportable segments, Electric and Natural Gas.

Electric (CenterPoint Energy)

The following table provides summary data of CenterPoint Energy’s Electric reportable segment for the periods presented:

59

The following table provides variance explanations by major income statement caption for the Electric reportable segment:

Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements.

60

Natural Gas (CenterPoint Energy)

The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment for the periods presented:

(1) Decrease in number of metered customers from 2024 to 2025 is primarily attributable to customer accounts associated with the divestiture of the Louisiana and Mississippi natural gas LDCs in March 2025. See Note 4 for additional detail.

61

The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment:

Income Tax Expense (Benefit). For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements.

62

HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS

Houston Electric’s CODM views net income as the measure of profit or loss for its reportable segment. Houston Electric consists of a 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 information regarding factors that may affect the future results of Houston Electric’s consolidated operations, see “Risk Factors” in Item 1A of Part I of this report.

The following table provides summary data of Houston Electric’s single reportable segment for the periods presented:

63

The following table provides variance explanations by major income statement caption for Houston Electric:

Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements.

64

CERC CONSOLIDATED RESULTS OF OPERATIONS

CERC’s CODM views net income as the measure of profit or loss for its reportable segment. CERC consists of a 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 information regarding factors that may affect the future results of CERC’s consolidated operations, see “Risk Factors” in Item 1A of Part I of this report.

The following table provides summary data of CERC’s single reportable segment for the periods presented:

(1) Decrease in number of metered customers is primarily attributable to customer accounts associated with the divestiture of the Louisiana and Mississippi natural gas LDCs in March 2025. See Note 4 for additional detail.

65

The following table provides variance explanations by major income statement caption for CERC:

Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements.

66

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes the Registrants’ cash flows by category for the periods presented:

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities:

(1)This change is primarily related to the receipt of proceeds at CenterPoint Energy and CERC from the issuance of customer rate relief bonds Texas by the Natural Gas Securitization Finance Corporation in 2023. For further details, see Note 7 to the consolidated financial statements.

Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities:

67

Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities:

Future Sources and Uses of Cash

Material Current and Long-term Cash Requirements. 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 2026 include the following:

The Registrants expect that anticipated cash needs for 2026 will be met with available cash flows from operations, proceeds from the sale of our Ohio natural gas LDC business, 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). The issuances 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.

68

The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for the periods presented. See Note 16 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2025.

(1)Houston Electric and CERC each consist of a single reportable segment.

The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2025:

(1)Balances reflect aggregate principal amounts outstanding and do not include unamortized discounts, premiums or issuance costs. See Note 12 to the consolidated financial statements for additional information.

(2)ZENS obligations are included in the 2029 column at their contingent principal amount of less than $0.1 million as of December 31, 2025. These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($507 million as of December 31, 2025), as discussed in Note 10 to the consolidated financial statements.

(3)The Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2025. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(4)For a discussion of commodity and other commitments, see Note 14(a) to the consolidated financial statements.

The table above does not include the following:

•estimated future payments for expected future AROs primarily estimated to be incurred after 2030. See Note 3(c) to the consolidated financial statements for further information.

69

•expected contributions to pension plans and other postretirement plans in 2026 and expected benefit payments to be paid by the pension and postretirement benefit plans. See Note 8(g) to the consolidated financial statements for further information.

•operating leases. See Note 19 to the consolidated financial statements for further information.

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 12 and guarantees as discussed in Note 14(b) to the consolidated financial statements and short-term leases, the Registrants have no off-balance sheet arrangements.

70

Regulatory Matters

TEEEF (CenterPoint Energy and Houston Electric)

For information about TEEEF, see Note 7 to the consolidated financial statements.

Hurricane Beryl (CenterPoint Energy and Houston Electric)

For information about Hurricane Beryl, see Note 7 to the consolidated financial statements.

May 2024 Storm Events (CenterPoint Energy and Houston Electric)

For information about May 2024 Storm Events, see Note 7 to the consolidated financial statements.

February 2021 Winter Storm Event (CenterPoint Energy, Houston Electric and CERC)

For information about the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements.

Indiana Electric Securitization of Generation Retirements (CenterPoint Energy)

For further information about the issuance of SIGECO Securitization Bonds, see Note 7 to the consolidated financial statements.

Indiana Electric CPCN (CenterPoint Energy)

BTAs

Indiana Electric pursued PTCs for solar projects following the passage of the IRA. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve an amended BTA to purchase the 191 MW Posey Solar project. Indiana Electric requested that project costs, net of PTCs, be recovered in rate base rather than a levelized rate, through base rates or the CECA mechanism, depending on which provides more timely recovery. On September 6, 2023, the IURC issued an order approving the CPCN. On March 7, 2025, SIGECO completed the acquisition of Posey Solar from Arevon for a purchase price of approximately $357 million. The Posey Solar project was placed in service in the second quarter of 2025 and is currently being recovered through base rates. In the applicable rate case, the IURC approved Indiana Electric’s request to convey PTCs to customers through the new tax adjustment rider. For further information, see Note 4 to the consolidated financial statements.

On January 10, 2023, Indiana Electric filed a CPCN with the IURC to acquire a wind energy generating facility located in the central region of MISO through a BTA, and on June 6, 2023, the IURC issued an order approving the CPCN, thereby authorizing Indiana Electric to purchase the wind generating facility. In August 2025, due to changing project considerations and concerns about customer affordability, Indiana Electric exited negotiations relating to this wind energy generating facility. On December 4, 2025, Indiana Electric filed a Notice of Termination in this proceeding.

PPAs

Indiana Electric sought approval in February 2021 for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which would provide equivalent equity return to offset imputed debt during the 25-year life of the PPA. In October 2021, the IURC approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising project costs caused by inflation and supply chain issues affecting the energy industry, Clenera LLC and Indiana Electric renegotiated the terms of the agreement to increase the PPA price and Indiana Electric subsequently filed a request with the IURC to amend the previously approved PPA with certain modifications. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays and estimated interconnection cost increases, on April 24, 2025, Indiana Electric provided notice that it was exercising its right to terminate the PPA, which terminated all further obligations of Indiana Electric with respect to the project.

On August 25, 2021, Indiana Electric filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden, which is developing a solar project in Vermillion County, Indiana, and 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 both PPAs. In March 2022, when the results of the MISO

71

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 has been delayed from 2024 to 2026. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with Oriden with certain modifications. On May 30, 2023, the IURC approved the Vermillion County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2028. On May 9, 2025, Indiana Electric and Oriden terminated 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 is targeted to be in operation in late 2026.

On April 14, 2025, Indiana Electric filed with the IURC seeking approval to purchase 170 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Tama County, Iowa. On June 3, 2025, an amendment to the PPA was filed with the IURC requesting an extension of the PPA’s term from 25 to 27 years. Indiana Electric received a final order from the IURC on November 5, 2025. The facility became operational on December 9, 2025. The power purchase costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA.

Indiana Electric 2025 IRP (CenterPoint Energy)

On December 5, 2025, Indiana Electric submitted its 2025 IRP with the IURC pursuant to applicable Indiana law requiring electric utilities to develop and submit to the IURC every three years (unless extended) an IRP that uses economic modeling to consider the costs and risks associated with available generation resource options to provide reliable, cost effective electric service for the next 20-year period. Indiana Electric’s 2025 IRP was developed following a series of public meetings and stakeholder discussions occurring in 2025 and identified both a preferred portfolio, which assumes the status quo for Indiana Electric’s service territory, and an alternative preferred portfolio, which includes a potential large load addition. Due to the phasing out of IRA renewable energy tax incentives pursuant to the OBBBA, declining accreditation from MISO for renewable energy and increased price pressure on resources due to, among other things, tariffs and ongoing supply chain issues, the 2025 IRP extends the timing for Indiana Electric’s generation transition plan. Accordingly, both the preferred portfolio and the alternative portfolio call for using the interconnection at F.B. Culley unit 2 for a 90 MW battery storage unit by 2028 and the conversion of the A.B. Brown units 5 and 6 gas turbines to a combined cycle gas turbine unit in the near- to mid-term, depending on load conditions. Decisions around F.B. Culley 3 will be reevaluated in the next IRP in 2028. The 2025 IRP includes the cancellation of nearly $1 billion in non-economical renewable projects. For more information regarding the risks associated with Indiana Electric’s execution of its generation transition plan and its IRP, see “Risk Factors - Risk Factors Affecting Operations - Indiana Electric’s execution of its generation transition plan...”

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 an emergency 202(c) order in December 2025 directing Indiana Electric to continue operating the unit through March 23, 2026. Indiana Electric has filed a complaint with the FERC to request creation of a cost recovery/cost allocation mechanism. If created, 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) order. 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) order that are not recovered through the FERC proceedings.

Natural Gas Combustion Turbines (CenterPoint Energy)

On June 17, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. On June 28, 2022, the IURC approved the CPCN. The $287 million turbine facility was constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana. Indiana Electric received approval for depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana Electric’s base rates include a return on and recovery of depreciation expense on the facility. A new approximately 23.5-mile pipeline was constructed and is operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. FERC granted a certificate to construct the pipeline on October 20, 2022. On January 7, 2025, the United States Court of Appeals for the D.C. Circuit affirmed FERC’s order granting the certificate. Indiana Electric granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. In the second quarter of 2025, 230 MW of the facility was

72

placed in service, and, due to a transformer manufacturing issue, the remaining 230 MW of the facility was placed in service in the third quarter of 2025. Indiana Electric received approval from the IURC on February 3, 2025, to recover for each combustion turbine by adjusting base rates as they are placed in service. The first turbine and second turbine are currently being recovered in base rates that were updated on June 17, 2025 and October 1, 2025, respectively.

Stewart-West Bay Transmission Project (CenterPoint Energy and Houston Electric)

On April 30, 2025, Houston Electric filed a CCN application with the PUCT for approval to replace a portion of a 138 kV double circuit transmission line in Galveston County, Texas that connects Houston Electric’s Stewart and West Bay substations. On June 27, 2025, an order was issued dismissing all opposing parties from the proceeding. On August 11, 2025, a notice of approval of Houston Electric’s application was issued. The project is estimated to cost approximately $105 million, but the actual capital cost of the project will depend on construction costs and other factors. Completion of construction and energization of the line is anticipated to occur in the third quarter of 2027.

Space City Solar Transmission Interconnection Project (CenterPoint Energy and Houston Electric)

On December 17, 2020, Houston Electric filed a CCN with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer, EDF Renewables. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first quarter of 2027.

Kilgore Transmission Project (CenterPoint Energy and Houston Electric)

On August 30, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Chambers County, Texas that will loop the existing 138 kV Chevron to Langston circuit number 86 on Houston Electric’s transmission system to Houston Electric’s planned Kilgore substation. On March 7, 2024, the PUCT issued a final order approving a route that was estimated to cost $60 million, including substation costs. The actual capital costs of the project, including the transmission line and the planned Kilgore substation, will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the fourth quarter of 2026.

Mill Creek Transmission Project (CenterPoint Energy and Houston Electric)

On November 17, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Harris and Montgomery Counties, Texas that will connect Houston Electric’s transmission system to Houston Electric’s planned Mill Creek substation. On November 21, 2024, the PUCT issued a final order approving a route estimated to cost $68 million. The actual capital costs of the project will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the second quarter of 2027.

Indiana Legislation (CenterPoint Energy)

Indiana Electric is evaluating legislation filed in Indiana’s 124th General Assembly, including House Bill 1002, a multi-faceted bill aimed at improving the affordability of electric rates. House Bill 1002 would do the following:

•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;

73

•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.

There are other bills moving through the 124th General Assembly, including legislation regarding surplus interconnection service, nuclear facility permits, and a bill on land use and developments that includes siting of battery energy storage systems.

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 carrying 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 timeline. This bill also lowered the system restoration costs threshold from $100 million to $50 million, provided the effectiveness tests are met.

•Senate Bill 482, effective September 1, 2025, results in increased penalties for assaulting a utility worker to a third-degree felony, equal to assaulting a first responder, and for harassing a utility worker to a Class A misdemeanor.

Transmission and Distribution System Resiliency Plans (CenterPoint Energy and Houston Electric)

Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed a revised SRP with the PUCT on January 31, 2025 for review and approval. The filed SRP proposed to invest approximately $5.75 billion over a three-year period from 2026 to 2028 for transmission and distribution infrastructure, information technology and cybersecurity assets and event response capability. This plan proposed 39 resiliency-enhancing measures and a microgrid pilot program to be implemented over the three-year period. The SRP as filed had an estimated capital cost of approximately $5.54 billion and an estimated operations and maintenance expense of approximately $211 million. Approximately $2.17 billion of such cost was for transmission-related investments, and approximately $3.58 billion was for distribution-related investments. Intervenor testimony was filed on April 8, 2025, and PUCT staff testimony was filed on April 15, 2025. On June 12, 2025, Houston Electric announced that it had reached a settlement agreement with parties to its SRP, which provides for approximately $3.18 billion in distribution-related investments. The proposed transmission investments were removed from the SRP and Houston Electric intends to implement such investments, as appropriate, outside of the SRP process. The agreement also includes the deferral of more than $240 million of the approximate $3.18 billion in SRP costs until the second half of 2029, which is intended to help reduce the bill impact for customers by spreading costs over a four-year period instead of three years. Once approved, and while some cost recovery would be deferred into 2029, it is expected that all SRP work agreed upon in the settlement agreement will be completed in the proposed 2025 to 2028 timeframe. At its November 14, 2025 open meeting, the PUCT approved the SRP. The final order issued on November 19, 2025 includes twenty-seven resiliency measures totaling approximately $2.68 billion in capital investments and an estimated $185 million in operations and maintenance expense. The approved SRP also includes the deferral of $217 million of the approximate $2.87 billion in SRP costs until the second half of 2029.

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, 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).

Minnesota Gas Rate Case. On November 1, 2023, CERC filed an application with the MPUC requesting an adjustment to delivery charges in 2024 and 2025 for the natural gas business in Minnesota. The requested increase was for approximately

74

6.5% or $85 million for 2024 and an additional approximately 3.7% or $52 million for 2025. The need for a rate change was primarily driven by continuing investment in the safety and reliability of the natural gas system, including new Intelis natural gas meters that feature an integrated safety shutoff valve, changes to depreciation rates that better reflect the actual life and salvage characteristics of assets and changes in other costs to serve customers. The request reflected a proposed 10.3% ROE on a 52.5% equity ratio. Interim rates for 2024 of $69 million, subject to refund, were implemented as of January 1, 2024. A request for interim rates of $33 million for 2025 was filed on September 30, 2024, approved at the December 3, 2024 hearing and approved by an order issued December 20, 2024. A unanimous settlement agreement was filed on November 25, 2024 and provided for an increase of $60.8 million for 2024 and an additional $42.7 million for 2025. The parties agreed to an overall cost of capital of 7.07% for 2024 and 2025. The ALJ filed a report on February 13, 2025 recommending that the MPUC approve the settlement agreement. As required by the December 20, 2024 order, the difference between 2024 interim rates and the settled amount of $60.8 million was refunded to customers in March 2025. Exceptions to the ALJ report were filed on April 18, 2025. On May 29, 2025, the MPUC approved the settlement agreement. A final order approving the settlement agreement was issued by the MPUC on June 27, 2025 and final rates were implemented on September 1, 2025.

Indiana Electric Rate Case. On December 5, 2023, Indiana Electric filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase was approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase was primarily driven by the continuing investment in the safety and reliability of the system and normal increases in operating expenses. The initial filing of the rate case reflected a proposed 10.4% ROE on a forecasted 55% equity ratio. Indiana Electric reached a settlement agreement with less than all parties and submitted the agreement to the IURC on May 20, 2024. The settlement reflected a proposed 9.8% ROE on a forecasted 55% equity ratio. The requested increase was lowered to $80 million, an 11% increase. Indiana Electric received a final order on February 3, 2025 approving the settlement with one modification that effectively capped the residential increase to 1.15% of the total increase, allocating the difference to other commercial and industrial customers. The final order approved the 9.8% ROE on a forecasted 55% equity ratio and increases revenues by $80 million.

Houston Electric Rate Case. On March 6, 2024, Houston Electric filed an application with the PUCT requesting authority to change rates and charges for electric transmission and distribution service. The requested increase was approximately $17 million (1%) for retail customers and $43 million (6.6%) for wholesale transmission service, excluding TCRF and rate case expenses. The need for a rate increase was primarily driven by continuing investment that has been made to support customer growth and to bolster the safety and reliability of Houston Electric’s transmission and distribution system. The request reflected a proposed 10.4% ROE and a 45% equity ratio. Errata testimony was filed to correct minor errors included in the initial filing, which reduced the requested increase to $56 million compared to then-current rates. Houston Electric reached a settlement agreement with certain parties and submitted the agreement to the PUCT on January 29, 2025. The settlement reflected a $47 million reduction in annual revenues and a 9.65% ROE and a weighted average cost of capital of 6.606% based upon an as-filed 4.29% cost of debt, an agreed ROE of 9.65% and an agreed regulatory capital structure of 56.75% long-term debt and 43.25% equity. A final order approving the settlement agreement was issued by the PUCT on March 13, 2025. Final retail delivery rates were implemented on April 28, 2025. Final wholesale transmission rates were superseded by interim TCOS rates that went into effect on the same date.

Ohio Gas Rate Case. CEOH filed its Application and Standard Filing Requirement in October 2024 and the related testimony in November 2024. The filing seeks a revenue requirement increase of approximately $100 million based on a requested ROE of 10.4% and an equity percentage of 54.13%. The need for a rate increase was primarily driven by continuing investment in the safety and reliability of the natural gas system. On May 16, 2025, the PUCO staff filed its staff report recommending a revenue requirement range of $340.8 million to $350.3 million and a net increase of $25.1 million to $34.6 million based on an ROE range from 9.05% to 10.07% with a capitalization ratio of 52.3% common equity and 47.7% long-term debt. The PUCO staff recommendation includes amortization over 49 years and 65 years for CEP and DRR regulatory assets, respectively, compared to CEOH’s proposal to amortize over seven years. On June 16, 2025, CEOH filed objections to the PUCO staff report and supplemental testimony. On July 11, 2025, CEOH filed a stipulation and recommendation that outlined the agreed upon terms between CEOH, the Federal Executive Agencies, Ohio Energy Group, the City of Dayton, the Retail Energy Supply Association, Interstate Gas Supply, LLC and the PUCO staff. One intervening party to the case, Spire Marketing, Inc., is a non-opposing party, while another intervening party to the case, the Office of the Ohio Consumers’ Counsel, filed its testimony in opposition to the stipulation and recommendation on July 29, 2025. The stipulation and recommendation included a revenue requirement of $371.3 million, which would result in a revenue requirement increase of $59.6 million based on a rate of return of 7.1% comprised of a ROE of 9.85% with a capitalization ratio of 52.9% common equity, 47.1% long-term debt at a cost of debt of 4.02%. The stipulation and recommendation amortization periods for CEP and DRR regulatory assets within base rates and within the rider mechanisms is 15 years. The stipulation and recommendation included an extension of the CEP rider and DRR through 2029 investment with revised residential caps for dollars per month per customer ranging from $2.75 for 2025 investment to $9.95 for 2029 investment for the CEP rider, and from $2.56 for 2025 investment to $7.69 for 2029 investment for DRR. The evidentiary hearing commenced on July 21, 2025. The stipulating parties were crossed by the Office of the Ohio Consumers’ Counsel on July 28 and August 4, 2025, and the Office of the Ohio

75

Consumers’ Counsel was crossed by the stipulating parties on July 29 and August 5, 2025. On July 29, 2025, a PUCO local public hearing was conducted. The parties filed initial briefs on August 26, 2025, and reply briefs on September 9, 2025. On November 21, 2025, CEOH filed a late filed exhibit to the stipulation and recommendation to include actual rate case expenses, which resulted in a revised revenue requirement increase of $59.7 million. The PUCO order was issued on January 7, 2026, modifying and adopting the stipulation and resolving all issues related to the case. The PUCO order modifications include: (1) extending the 15-year amortization periods for the CEP and DRR deferral balances to 25 years, which had a $7.9 million negative impact on the revenue requirement, and (2) a ROE of 9.79%, resulting in a rate of return of 7.07%, which had a $0.6 million negative impact on the revenue requirement. These two modifications result in a revised revenue requirement increase of $51.3 million and a total revenue requirement of $363 million. Revised rates became effective on a services rendered basis effective January 12, 2026.

The table below reflects significant applications pending or completed since the Registrants’ combined 2024 Form 10-K was filed with the SEC through the date of the filing of this Form 10-K:

76