What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2026-02-19 compared with 2025-02-20 · 562 added, 593 removed, 759 unchanged (60% of the section changed)

5 unchanged sentences

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 stated otherwise.

No registrant makes any representations as to the information related solely to CenterPoint Energy, Inc.

or the subsidiaries of CenterPoint Energy, Inc.

other than itself.

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.

CenterPoint Energy is a public utility holding company.

2 unchanged sentences

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.

is an indirect, wholly-owned subsidiary of CenterPoint Energy, which (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi 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 February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses.

The transaction is expected to close in the first quarter of 2025.

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.

4 unchanged sentences

Below is a summary of CenterPoint Energy’s reportable segments as of December 31, 2025.

For a detailed description of the assets included in each reporting segment, see Part I, Item 1.

• The Electric reportable segment includes electric transmission and distribution services that are subject to rate regulation in Houston Electric’s and Indiana Electric’s service territories, as well as the impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility and energy delivery services to electric customers and electric generation assets to serve electric customers and optimize those assets in the wholesale power market in Indiana Electric’s service territory.

• The Natural Gas reportable segment includes (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial and industrial customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas;

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.

• 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;

and (iii) home appliance maintenance and repair services to customers in Minnesota and home repair protection plans to natural gas customers in Indiana, Mississippi, Ohio and Texas through a third party.

• The Corporate and Other reportable segment includes (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 operations that support the business operations of CenterPoint Energy;

(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.

5 unchanged sentences

Factors Influencing Our Businesses and Industry Trends

We are an energy delivery company with electric transmission and distribution, power generation, and natural gas distribution operations that serve more than seven million metered customers across six jurisdictions.

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 which were set in 2021.

These include our ten-year capital plan from 2021 through 2030, a focus on targeting controllable operations and maintenance savings for the benefit of our customers, prudent capital funding including divestitures of non-core assets, and net zero and GHG emissions reduction goals.

Our focus continues to be on the growth of our regulated utility businesses including our electric and gas utility operations, which comprise over 95% of our earnings for the year ended December 31, 2024.

See Note 16 to the consolidated financial statements for further details.

Pursuant to this business strategy and in light of the nature of our businesses, significant amounts of capital investment are reflected in our current 10-year capital plan, which has increased to nearly $47.5 billion through 2030.

These investments include a focus on additional system resiliency, reliability, and grid modernization.

These investments are not only intended to meet our customers’ current needs, but are also in anticipation for further organic growth and load growth from increased electrification in our service territories.

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 the divestitures of our Arkansas and Oklahoma LDC businesses in 2022, our Energy Systems Group divestiture in 2023 and the proposed sale of our Louisiana and Mississippi natural gas LDC businesses, which is expected to close in the first quarter of 2025), and issuances of equity and debt in the capital markets, including the issuance of non-recourse securitization bonds at Houston Electric related to costs incurred during the year ended December 31, 2024 due to the May 2024 Storm Events and Hurricane Beryl.

We strive to maintain investment grade ratings for our securities to access the capital markets on terms we consider reasonable.

A reduction in our ratings generally would increase 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 new capital on terms we consider attractive.

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

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.

The regulation of electric transmission, distribution and generation facilities as well as natural gas pipelines and related facilities by federal and state regulatory agencies affects our businesses.

In accordance with applicable regulations, we are making, and will continue to make, significant capital investments in our service territories under our capital plan to help operate and maintain safer, more reliable and growing electric and natural gas systems.

The current economic environment (e.g., sustained higher interest rates and higher relative levels of inflation in the United States) discussed further below could result in heightened regulatory scrutiny as these regulatory agencies seek to reduce the financial impact of utility bills on customers.

While greater than 80% 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, the balance is expected to be recovered through base rate cases.

Indiana Electric filed a rate case during 2023, and Houston Electric and CERC’s Ohio jurisdiction filed rate cases in 2024.

The outcome of these base rate proceedings will determine, among other things, the ability to recover certain capital

investments within those jurisdictions.

The outcome of these base rate proceedings is uncertain and may be impacted by the current economic environment.

CERC’s Texas and Minnesota gas jurisdictions filed rate cases in 2023, which were settled in 2024.

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 the evaluation of net income and capital expenditures, among other things, 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.

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, environmental impacts, 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 Natural Gas in Indiana, Louisiana, Mississippi, Minnesota and Ohio, as applicable.

CenterPoint Energy’s and CERC’s Natural Gas in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms, although fixed customer charges are historically higher in Texas for Natural Gas compared to its other jurisdictions.

As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s Natural Gas’ results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories.

Each state has a unique economy and is driven by different industrial sectors.

Our largest customers reflect the diversity in industries in the states across our footprint.

For example, Houston Electric is largely concentrated in Houston, a diverse economy where a higher percentage of employment is tied to the energy sector relative to other regions of the country.

Although the Houston area represents a large part of our customer base, we have a diverse customer base throughout the various states our utility businesses serve.

In Minnesota, for instance, education and health services are the state’s largest sectors.

Indiana and Ohio are impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest such as automotive, feed and grain processing.

Some industries are driven by population growth like education and health care, while others may be influenced by strength in the national or international economy.

Adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for our services.

Long-term national trends indicate residential customers have reduced their energy consumption, which could adversely affect 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.

Management expects residential meter growth for Houston Electric to remain in line with long term trends at approximately 2%.

Management additionally anticipates significant increased electric load growth demand in our Houston Electric service territory, including in relation to the expected expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics.

Typical customer growth in the jurisdictions served by the Natural Gas reportable segment is approximately 1%.

Management expects residential meter growth for CERC to remain in line with long term trends at approximately 1%.

Inflation and high interest rates and a recessionary environment could potentially adversely impact CenterPoint Energy’s ability to execute on its 10-year capital plan.

The inability to execute on our capital plan may result in lost future revenues for CenterPoint Energy.

Additionally, these economic conditions may affect customers’ ability to pay their utility bills which may preclude our ability to collect balances due from such customers.

Further, the global supply chain has experienced significant disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and political instability, import tariffs and trade agreements, labor shortages, resource availability, long lead times, manufacturer production limitations, delivery delays, inflation and severe weather events.

These disruptions have adversely impacted the utility industry.

Like many of our peers, we have experienced disruptions to our supply chain, as well as increased prices, and may continue to experience such disruptions in the future.

For example, President Trump has expressed a desire to impose substantial new or increased tariffs, and in February 2025, imposed tariffs on several countries and certain imports into the United States.

These tariffs, as well as any new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could increase or cause volatility in the cost of and negatively impact our ability to procure materials, supplies (such as natural gas) or services necessary for our business and capital plan, lead to scarcity of resources and labor necessary for our business and capital plan, further extend lead time or otherwise negatively impact the supply chain and our ability to timely execute our capital plan.

To the extent adverse economic conditions, including supply chain disruptions, affect our suppliers and customers as well as our ability to meet our capital plan and generation transition plan, including with respect to developing and constructing new generation facilities at the cost and scale and on the timelines that we anticipate, results from our energy delivery businesses may suffer.

For more information, see Note 14 to the consolidated financial statements.

Further, in response to concerns for protecting the environment, we have strived to take a leading stance in the transition to safer and cleaner energy by being the first combined electric and natural gas utility with regulated generation assets to adopt net zero for its Scope 1 and certain Scope 2 emissions by 2035 goals.

In addition, we set a Scope 3 emission reduction goal across our multi-state footprint by committing to help our residential and commercial customers reduce GHG emissions attributable to their end use of natural gas by 20% to 30% by 2035 from a 2021 baseline.

Our capital plan supports these goals.

For more information regarding CenterPoint Energy’s net zero and GHG emissions reduction goals and the risks associated with them, see Part I, Item 1A.

“Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks...”

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

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

May 2024 Storm Events and Hurricane Beryl.

Houston Electric’s service territory experienced sudden and destructive severe weather events in May 2024 that included hurricane-like winds and tornadoes.

Subsequently, on July 8, 2024, Hurricane Beryl made landfall in Texas, bringing sustained winds, storm surges and torrential rain into Houston Electric’s service territory.

The May 2024 Storm Events and Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in electric service interruptions peaking at an estimated 922,000 customers and more than 2.1 million customers, respectively.

Various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl, the efforts made by Houston Electric to prepare for, and respond to, this event, including the electric service outage issues, and the procurement of TEEEF.

Moreover, additional governmental and regulatory agencies and other entities may conduct such inquiries and investigations, as well.

On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl.

Texas Lieutenant Governor Patrick has publicly urged the PUCT to hold Houston Electric, rather than ratepayers, responsible for paying $800 million, which was the amount the PUCT had previously approved Houston Electric to recover from ratepayers pursuant to Texas legislation passed after the 2021 Winter Storm Event relating to emergency responsiveness and the leasing of temporary generation units.

Additionally, legislation has been proposed in Texas to, among other things, require the PUCT to review TEEEF leased by TDUs, disallow any leases that do not conform to the terms of the proposed legislation (which include, among other things, requirements relating to the speed with which TEEEF may be deployed), disallow recovery of costs associated with such disallowed leases, and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF.

There are significant uncertainties around these inquiries and investigations and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed or changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom.

Further, on January 22, 2025, a putative shareholder of CenterPoint Energy, Donel Davidson, filed a derivative petition in Harris County District Court, Texas, alleging breach of fiduciary duty and unjust enrichment on behalf of CenterPoint Energy against certain of its current and former directors and officers citing, in part, the topics of these inquiries and investigations.

The action seeks to recover damages and other relief from the defendants on behalf of CenterPoint Energy.

Additionally, on February 12, 2025, a second putative shareholder of CenterPoint Energy made a demand on the Board to investigate the same basic allegations raised in the derivative petition filed by Donel Davidson.

Houston Electric announced an initial hurricane preparedness and response action plan to the PUCT on July 25, 2024 to enhance the resiliency of the electric system through various investments.

Following a meeting with Texas Governor Abbott on August 1, 2024, Houston Electric publicly committed to accelerating its previously announced initial hurricane preparedness and response action plan.

Accordingly, Houston Electric announced that it was withdrawing its application for approval of its transmission and distribution system resiliency plan with the PUCT in order to focus on addressing the impacts of Hurricane Beryl in its service territory and accelerating preparedness and resiliency efforts for the remaining storm season, and the withdrawal granted by the PUCT.

On August 5, 2024, Houston Electric announced the launch of its GHRI.

Subsequently, Houston Electric announced the completion of core resiliency actions as part of the first phase of its GHRI, which included certain vegetation management and pole installation goals.

In September 2024, Houston Electric announced the launch of the second phase of its GHRI, which included a series of resiliency plans to install new poles, manage higher-risk vegetation and install certain automated devices prior to the start of the 2025 hurricane season as part of its efforts to strengthen grid resiliency, improve public and customer communications and strengthen local, community and emergency partnerships.

Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed the SRP with the PUCT on January 31, 2025, which proposes investing approximately $5.75 billion over a three-year period for transmission and distribution infrastructure, information technology and cybersecurity assets, and event response capability.

Houston Electric announced on August 28, 2024 its proposal to forego approximately $110 million of profit related to its storm hardening and TEEEF efforts, which would be represented by (1) Houston Electric not seeking to recover approximately $70 million in incremental storm hardening costs incurred in connection with accelerated operational activities after Hurricane Beryl;

and (2) Houston Electric not filing, beginning in 2028, for approximately $40 million in anticipated equity profit associated with load-shed orientated TEEEF leased by Houston Electric through the remaining regulatory life of the leases in 2032 as new dispatchable generation is likely to come online in the state of Texas as a result of the Texas Energy Fund.

Additionally, on December 19, 2024, Houston Electric announced a proposal to release Houston Electric’s 15 large 27 MW to 32 MW TEEEF units to the San Antonio area prior to the summer of 2025 in an effort to help ERCOT address a potential energy shortfall and Load Shed risk and to provide additional electric generation capacity to support growing energy demand in the greater San Antonio region.

Under the proposal, Houston Electric would not receive revenue or profit from ERCOT and would also not charge Houston-area customers for these TEEEF units for the period when they are in San Antonio serving ERCOT, which is currently expected to be for a period of up to two years.

Houston Electric would anticipate receiving revenues from one or more future transactions after the period the units are utilized to temporarily serve an energy need in the San Antonio area, and would therefore plan to continue to not charge customers for these units for any future periods.

As of the date of the filing of this Form 10-K, Houston Electric estimates that the value of the TEEEF units to be removed from the rate base as a result of the aforementioned proposal will be approximately $375 million.

The proposal has not been finalized and is subject to the negotiation of definitive documentation among the relevant parties, as well as being subject to the approval of ERCOT and other stakeholders.

It is not certain that mutually agreeable definitive documentation will be entered into at all or that all approvals will be obtained.

For more information, see Note 7, 12 and 14 to the consolidated financial statements and “Liquidity and Capital Resources” below.

Equity Transactions.

On August 9, 2024, CenterPoint Energy issued 9,754,194 shares of Common Stock in an underwritten public offering at a price of $25.36 per share, for net proceeds of $247 million after deducting issuance costs.

For further information, see Note 11 to the consolidated financial statements.

On January 10, 2024, CenterPoint Energy entered into an Equity Distribution Agreement with certain financial institutions 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 $500 million.

Sales of Common Stock 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 of 1933, as amended.

CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations.

During the year ended December 31, 2024, CenterPoint Energy issued 8,790,848 shares of Common Stock through the ATM Managers under the Equity Distribution Agreement, representing aggregate cash proceeds of $247 million, which was net of compensation paid by CenterPoint Energy to the ATM Managers of $2 million.

As of December 31, 2024, CenterPoint Energy had not entered into any forward sale agreements under the at-the-market program.

Additionally, as of December 31, 2024, CenterPoint Energy had $250 million of remaining capacity available under the program.

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.

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.

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 February 19, 2024, CERC Corp.

entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses.

The purchase price for the Louisiana and Mississippi natural gas LDC businesses is $1.2 billion and subject to adjustment as set forth in the LAMS Asset Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing.

The transaction is not subject to a financing condition and is expected to close by the end of the first quarter of 2025, subject to satisfaction of customary closing conditions.

The businesses include approximately 12,000 miles of main pipeline in Louisiana and Mississippi serving more than 300,000 customers.

The Louisiana and Mississippi natural gas LDC businesses are reflected in CenterPoint Energy’s Natural Gas reportable segment and CERC’s single reportable segment, as applicable.

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.

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

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 to date in 2024 and to date in 2025, see “—Liquidity and Capital Resources —Regulatory Matters” below.

Debt Transactions.

In 2024, CenterPoint Energy issued or borrowed a combined $4.0 billion in new debt, including Houston Electric’s issuance of $900 million aggregate principal amount of general mortgage bonds and a $500 million term loan, CERC’s issuance of $400 million principal amount of senior notes, SIGECO’s issuance of $160 million aggregate principal amount of first mortgage bonds, and CenterPoint Energy’s issuance of $700 million aggregate principal amount of senior notes and $1.3 billion aggregate principal amount of junior subordinated notes.

During 2024, CenterPoint Energy repaid or redeemed a combined $0.9 billion of debt, including $500 million of its senior notes, $350 million of its floating rate senior notes and $22 million of SIGECO’s first mortgage bonds.

For further information about debt transactions in 2024, see Note 12

to the consolidated financial statements.

Subsequent Events .

On January 29, 2025, CenterPoint Energy, Houston Electric, CERC and SIGECO each entered into Extension Agreements to, among other things, extend the maturity date of the lenders’ commitments under each of their respective Credit Agreements by one year, from December 6, 2027 to December 6, 2028.

Additionally, on January 31, 2025, SIGECO issued $165 million aggregate principal amount of 5.69% First Mortgage Bonds, Series 2025A, Tranche A due 2055.

Total net proceeds from SIGECO’s January 2025 issuance of first mortgage bonds, net of transaction expenses and fees, were approximately $164 million, which will be used for the acquisition of Posey Solar.

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

1 unchanged sentence

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 Louisiana and Mississippi natural gas LDC businesses, 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, including in relation to the expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, as well as the effects of energy efficiency measures and demographic patterns;

• 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 Indiana Electric’s generation transition plan as part of its IRPs and Houston Electric’s GHRI and SRP;

• our ability to successfully construct, operate, repair and maintain electric generating facilities, natural gas facilities, TEEEF and electric transmission facilities, including complying with applicable environmental standards and the implementation of a well-balanced energy and resource mix, as appropriate;

• 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 TEEEF leases and restoration costs relating to the May 2024 Storm Events and Hurricane Beryl, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings;

• our ability to finalize Houston Electric’s proposal to release its 15 large 27 MW to 32 MW TEEEF units to the San Antonio area and complete one or more other future transactions involving the units on acceptable terms and conditions within the anticipated timeframe;

• economic conditions in regional and national markets, including changes to inflation and interest rates, and their effect on sales, prices and costs;

• weather variations and other natural phenomena, including the impact of severe weather events on operations, capital, legislation and/or regulations, such as 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, tariffs, legislation, bans, potential retaliatory trade measures taken against the United States or related governmental action, as well as armed conflicts, including the conflict in the Middle East and any broader related conflict, and the conflict in Ukraine, and the related sanctions on certain Russian entities;

• disruptions to the global supply chain, including as a result of volatility in commodity prices, trade agreements, geopolitical and economic uncertainty, regulatory and policy instability, severe weather events, tariffs, bans, retaliatory trade measures, legislation and governmental action impacting the supply chain, that could prevent CenterPoint Energy from securing the resources needed to, among other things, fully execute on its 10-year capital plan or achieve its net zero and GHG emissions reduction goals;

• 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;

• 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;

1 unchanged sentence

and world financial markets and supply chains, potential regulatory actions and changes in customer and stakeholder behavior relating thereto;

• state and federal legislative and regulatory actions or developments affecting various aspects of our businesses, including, among others, any actions resulting from the May 2024 Storm Events and/or Hurricane Beryl, energy

deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;

• our ability to execute Houston Electric’s GHRI and SRP;

• direct or indirect effects on our facilities, resources, operations, reputation and financial condition resulting from terrorism, cyberattacks or intrusions, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, derecho events, ice storms and other severe weather events, terrorism, wildfires, pandemic health events, geopolitical conflict or other occurrences;

• risks relating to potential wildfires, including damages to our network and losses in excess of insurance liability coverage;

• tax legislation, including the effects of or changes to or the repeal of the IRA (which includes but is not limited to any potential changes to tax rates, CAMT imposed, tax credits and/or interest deductibility), as well as any changes in tax laws under the current or future administrations, and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;

• 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;

• matters affecting regulatory approval, legislative actions, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or cancellation or in costs that cannot be recouped in rates;

• local, state and federal legislative and regulatory actions or developments relating to the environment, including, among others, those related to global climate change, 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 net zero and GHG emissions reduction goals;

• 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;

• the availability and prices of raw materials and services and changes in labor for current and future construction projects and operations and maintenance costs, including our ability to control such costs;

• 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;

• 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 debt capital markets, and impacts on our vendors, customers and suppliers;

• 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 the May 2024 Storm Events and 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 management and key employees and maintain good labor relations;

• changes in technology, particularly 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 and adapt to technological changes;

• our success in adopting, developing and deploying AI;

• the impact of climate change and alternate energy sources on the demand for natural gas and electricity generated or transmitted by us;

• 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 new presidential administration;

• CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including its net zero and GHG emissions reduction goals and its operations and maintenance expenditure goals;

• 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;

4 unchanged sentences

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, read “Risk Factors” in Part I, Item 1A of this report.

Income available to common shareholders for the years ended December 31, 2024, 2023 and 2022 was as follows:

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:

Year Ended December 31, Favorable (Unfavorable)

3 unchanged sentences

Natural Gas (1)

Total Utility Operations 1,235 1,187 1,095 48 92

570 566 533 4 33

Corporate & Other (2)

(223) (218) (320) (5) 102

Total CenterPoint Energy $ 1,052 $ 1,019 $ 867 $ 33 $ 152

(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

CenterPoint Energy reported income available to common shareholders of $1,019 million for 2024 compared to income available to common shareholders of $867 million for 2023.

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

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;

• an increase in income available to common shareholders of $104 million for Corporate and Other, 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.

• 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

CenterPoint Energy reported income available to common shareholders of $867 million for 2023 compared to income available to common shareholders of $1,008 million for 2022.

Income available to common shareholders decreased $141 million primarily due to the following items:

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;

• a decrease in income available to common shareholders of $233 million for Corporate and Other, primarily due to a pre-tax net gain of $86 million on the sale of Energy Transfer equity securities in 2022 further discussed in Note 10 to the consolidated financial statements, partially offset by $45 million of costs associated with early redemption of long-term debt in first quarter 2022.

The decrease is also due to a loss on sale of $13 million and current tax expense of

$32 million related to the divestiture of Energy Systems Group further discussed in Note 4 to the consolidated financial statements, as well as $19 million due to remeasurement of deferred income tax balances.

• 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.

6 unchanged sentences

Electric (CenterPoint Energy)

The following table provides summary data of CenterPoint Energy’s Electric reportable segment:

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

Year Ended December 31, Favorable (Unfavorable)

32 unchanged sentences

Customer growth 26 26

Energy efficiency, offset in operation and maintenance below

Energy efficiency, partially offset in operation and maintenance below 29 5

Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (18) (20)

1 unchanged sentence

Miscellaneous revenues, including service connections and off-system sales

Lost revenues as a result of outages associated with Hurricane Beryl

Lost revenues as a result of outages associated with Hurricane Beryl in 2024

Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below (62) (70)

5 unchanged sentences

Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above (19) 65

$ (72) $ (22)

Operation and maintenance

Transmission costs billed by transmission providers, offset in revenues above $ (40) $ (124)

Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl

Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl in 2024

Contract services (34) 16

1 unchanged sentence

Corporate support services

Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 3 —

Labor and benefits (9) 4

3 unchanged sentences

Ongoing additions to plant-in-service $ (74) $ (79)

Lease expense associated with TEEEF units no longer eligible for regulatory deferral (59) —

Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 64 74

2 unchanged sentences

Incremental capital projects placed in service, and the impact of updated property tax rates

$ (17) $ (26)

Franchise fees and other taxes — (6)

12 unchanged sentences

Natural Gas (CenterPoint Energy)

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

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

Year Ended December 31, Favorable (Unfavorable)

11 unchanged sentences

Other Income (Expense):

Gain on sale — — 303 — (303)

(49) — — (49) —

Interest expense and other finance charges (208) (207) (188) (1) (19)

14 unchanged sentences

Commercial and industrial 289,166 304,606 303,841 (5) % — %

Total 4,368,534 4,313,954 4,266,055 1 % 1 %

4,029,085 4,368,534 4,313,954 (8) % 1 %

(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.

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

4 unchanged sentences

$ 384 $ (368)

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — (38)

Gross receipts tax, offset in taxes other than income taxes below 14 1

4 unchanged sentences

Customer growth 14 14

Customer rates

Customer rates and impact of the change in rate design

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 (182) $ —

Total $ 436 $ (229)

1 unchanged sentence

Cost of natural gas, offset in revenues above $ (384) $ 368

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 23

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 58 —

Total $ (326) $ 368

6 unchanged sentences

Contract services (10) (6)

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 53 —

Labor and benefits

4 unchanged sentences

$ (60) $ (29)

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 2

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 39 —

Total $ (21) $ (29)

1 unchanged sentence

Gross receipts tax, offset in revenues above

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 1

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 15 —

Incremental capital projects placed in service, and the impact of updated property tax rates

Total $ (8) $ 8

Gain on Sale of Arkansas and Oklahoma Natural Gas businesses in 2022 $ — $ (303)

Loss on sale of Louisiana and Mississippi natural gas LDC businesses $ (49) $ —

Total $ (49) $ —

2 unchanged sentences

Other, primarily AFUDC and impacts of regulatory deferrals (5) (7)

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 10 —

Total $ (1) $ (19)

Other income (expense), net

Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60

Other income, including AFUDC - Equity

Changes to non-service benefit cost

Other income, including interest income from affiliated companies and AFUDC - Equity

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 (1) —

Total $ 13 $ (1)

6 unchanged sentences

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, read “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 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:

Year Ended December 31, Favorable (Unfavorable)

8 unchanged sentences

Bond Companies 12 78 159 66 81

Total 2,984 2,683 2,581 (301) (102)

Total expenses

3,032 2,984 2,683 (48) (301)

Operating Income 1,052 955 994 97 (39)

25 unchanged sentences

Miscellaneous revenues 13 1

Lost revenues as a result of outages associated with Hurricane Beryl

Lost revenues as a result of outages associated with Hurricane Beryl in 2024

Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (18) (19)

4 unchanged sentences

Transmission costs billed by transmission providers, offset in revenues above $ (40) $ (124)

Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl

Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl in 2024 112 (112)

Contract services (29) 7

6 unchanged sentences

Ongoing additions to plant-in-service $ (47) $ (95)

Lease expense associated with TEEEF units no longer eligible for regulatory deferral

Total $ (107) $ (95)

Taxes other than income taxes

Franchise fees and other taxes $ (7) $ (2)

Incremental capital projects placed in service, and the impact of changes to tax rates $ (17) $ (26)

Franchise fees and other taxes — (7)

Total $ (17) $ (33)

Bond Companies expense

Bond Companies

Operations and maintenance and depreciation expense, offset in revenues above

5 unchanged sentences

Interest expense on Securitization Bonds

Lower outstanding principal balance, offset in revenues above

Change in outstanding principal balance, offset in revenues above $ (3) $ 5

Total $ (3) $ 5

1 unchanged sentence

Other income, including AFUDC - equity $ 7 $ 9

Bond Companies — 4

Bond Companies interest income, offset in other line items

Total $ 5 $ 9

6 unchanged sentences

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, read “Risk Factors” in Item 1A of Part I of this report.

The following table provides summary data of CERC’s single reportable segment:

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:

Year Ended December 31, Favorable (Unfavorable)

27 unchanged sentences

278,500 293,959 293,235 (5) % — %

Total 4,252,543 4,198,623 4,150,910 1 % 1 %

3,912,922 4,252,543 4,198,623 (8) % 1 %

(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.

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

2 unchanged sentences

Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ 372 $ (367)

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — (38)

Gross receipts tax, offset in taxes other than income taxes below

5 unchanged sentences

Customer rates

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 (182) —

Total $ 419 $ (224)

1 unchanged sentence

Cost of natural gas, offset in revenues above $ (372) $ 367

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 23

Total $ 367 $ 751

Non-utility costs of revenues, including natural gas

Other, primarily non-utility cost of revenues $ — $ 1

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 58 —

Total $ (314) $ 367

3 unchanged sentences

Contract services (12) (6)

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 53 —

Labor and benefits (25) 8

4 unchanged sentences

$ (58) $ (29)

Indiana lower depreciation rates from recent rate order — —

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 2

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 39 —

Total $ (19) $ (29)

1 unchanged sentence

Gross receipts tax, offset in revenues above

Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 1

Incremental capital projects placed in service, and the impact of updated property tax rates

Net gain on sale of Arkansas and Oklahoma Natural Gas businesses $ — $ (557)

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 15 —

Gain on sale of Louisiana and Mississippi natural gas LDC businesses

Total $ 46 $ —

2 unchanged sentences

Other, primarily AFUDC and impacts of regulatory deferrals (4) (8)

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 $ 10 $ —

Total $ 3 $ (19)

Other income (expense), net

Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60

Other income, including AFUDC - Equity

Changes to non-service benefit cost

Other income, including interest income from affiliated companies and AFUDC - Equity

Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 $ (1) $ —

Total $ 13 $ (2)

20 unchanged sentences

Changes in working capital (1)

Changes in current regulatory assets and liabilities (1) (1,238) (4) (1,183) 1,085 26 986

Changes in non-current regulatory assets and liabilities (535) (472) (85) (276) (115) (78)

Lower pension contribution

(231) (275) 48 (1,372) 191 (1,266)

Other non-current assets

511 370 274 (580) (500) (135)

Other non-current liabilities

189 52 (142) (57) (15) 49

Higher pension contribution

(100) — — 2 — —

Other (98) (27) (11) (46) 15 (45)

9 unchanged sentences

(in millions)

Proceeds from the sale of equity securities $ — $ — $ — $ (702) $ — $ —

Payment for asset acquisition

$ (357) $ — $ — $ — $ — $ —

Net change in capital expenditures (357) (189) (88) $ (112) $ (363) $ 180

17 unchanged sentences

Increased payment of Common Stock dividends (52) — — (37) — —

Decreased (increased) payment of preferred stock dividends 50 — — (1) — —

Payment of obligation for finance lease — — — 485 485 —

Decreased payment of preferred stock dividends

Net change in notes payable from affiliated companies — 54 291 — 642 —

Change in contribution from parent — (41) (210) — (258) 211

Change in dividend to parent

— 41 (288) — 28 54

Change in contribution from parent

— (750) (290) — (41) (210)

Other 67 57 2 (3) 1 (2)

3 unchanged sentences

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.

Capital expenditures (other than expenditures associated with the May 2024 Storm Events and Hurricane Beryl) are expected to be used for investment in infrastructure.

These capital expenditures are anticipated to enhance reliability and safety, increase resiliency and expand our systems through value-added projects.

Substantial capital expenditures are also expected for restoration costs associated with Hurricane Beryl, as further described below.

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:

3 unchanged sentences

$ 6,695 $ 4,031 $ 2,198

Estimated restoration costs associated with May 2024 Storm Events (2)

Estimated restoration costs associated with Hurricane Beryl (2)

Scheduled principal payments on Securitization Bonds

Scheduled principal payments on debt instruments, excluding Securitization Bonds

Expected contributions to pension plans and other postretirement plans

(1) Excludes expenditures for the restoration costs associated with the May 2024 Storm Events and Hurricane Beryl.

(2) Represents cash requirements associated with estimated storm restoration costs for 2025.

The Registrants expect that anticipated cash needs for 2025 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, including the issuance of non-recourse securitization bonds at Houston Electric related to costs incurred during the year ended December 31, 2024 due to the May 2024 Storm Events and Hurricane Beryl, anticipated cash flows from operations, and, with respect to CenterPoint Energy and CERC, proceeds from commercial paper and the sale of the Louisiana and Mississippi natural gas LDC businesses, if and when completed (the transaction is expected to close in the first quarter of 2025).

Issuances of debt securities in the capital markets, funds raised in the commercial paper markets, term loans and additional credit facilities may not, however, be available on acceptable terms.

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.

For more information regarding the May 2024 Storm Events and Hurricane Beryl, see Notes 7, 12 and 14 to the consolidated financial statements as well as “Risk Factors” in Part I, Item 1A of this report.

The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for 2025 through 2029.

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.

9 unchanged sentences

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

Capital Expenditures for Climate-Related Projects .

As part of its approximately $47.5 billion 10-year capital expenditure plan, which concludes in 2030, CenterPoint Energy anticipates spending over $3 billion in lower-emissions energy investments and enablement, which may be used to support, among other things, renewable energy generation.

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

2 unchanged sentences

CenterPoint Energy

Short-term borrowings $ 500 $ — $ — $ — $ — $ — $ 500

Securitization Bonds (1) 40 37 39 41 43 514 714

2 unchanged sentences

Interest payments — other long-term debt (3) 1,024 956 914 749 3,170 8,223 15,036

Short-term borrowings 500 — — — — — 500

Commodity and other commitments (4) 978 946 781 630 681 2,919 6,935

1 unchanged sentence

Houston Electric

Short-term borrowings $ 500 $ — $ — $ — $ — $ — $ 500

Securitization Bonds (1) 27 23 24 25 26 277 402

Other long-term debt (1) 300 300 500 — 500 7,679 9,279

Interest payments — Securitization Bonds (3) 22 17 16 14 13 62 144

Interest payments — other long-term debt (3) 401 383 379 353 2,659 3,466 7,641

Short-term borrowings 500 — — — — — 500

Total cash requirements $ 1,250 $ 723 $ 919 $ 392 $ 3,198 $ 11,484 $ 17,966

6 unchanged sentences

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 $9 million as of December 31, 2024.

(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.

7 unchanged sentences

See Note 3(c) to the consolidated financial statements for further information.

• expected contributions to pension plans and other postretirement plans in 2025.

• 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.

2 unchanged sentences

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(c) to the consolidated financial statements) and short-term leases, the Registrants have no 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.

Regulatory Matters

Houston Electric TEEEF

For information about Houston Electric’s TEEEF, see Note 7 to the consolidated financial statements.

Hurricane Beryl

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

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

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.

2 unchanged sentences

Indiana Electric CPCN (CenterPoint Energy)

On February 23, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to purchase the Posey Solar project.

On October 27, 2021, the IURC issued an order approving the CPCN, authorizing Indiana Electric to purchase the Posey Solar project through a BTA to acquire its solar array assets for a fixed purchase price and approved recovery of costs via a levelized rate over the anticipated 35-year life.

Due to community feedback and rising project costs caused by inflation and supply chain issues affecting the energy industry, Indiana Electric, along with Arevon, the developer, announced plans in January 2022 to downsize the Posey Solar project to 191 MW.

Indiana Electric collaboratively agreed to the scope change, and on February 1, 2023, Indiana Electric entered into an amended and restated BTA that was contingent on further IURC review and approval.

On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve the amended BTA.

With the passage of the IRA, Indiana Electric can now pursue PTCs for solar projects.

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.

The Posey Solar project is expected to be placed in service in the second quarter of 2025 and recovered through base rates.

On July 5, 2022, Indiana Electric entered into a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price.

A CPCN for the project was filed with the IURC on July 29, 2022.

On September 21, 2022, an agreement in principle was reached resolving all the issues between Indiana Electric and OUCC.

The Stipulation and Settlement agreement was filed on October 6, 2022 and a settlement hearing was held on November 1, 2022.

On January 11, 2023, the IURC issued an order approving the settlement agreement authorizing Indiana Electric to purchase and acquire the Pike County Solar project through a BTA and approved the estimated cost.

The IURC also designated the

project as a clean energy project under applicable Indiana regulations, approved the proposed levelized rate and associated ratemaking and accounting treatment.

Due to inflationary pressures, the developer disclosed that costs exceeded the agreed upon levels in the BTA.

After negotiations, Indiana Electric and the developer were not able to agree upon updated pricing.

As a result, on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate the BTA, which terminated all further obligations of Indiana Electric with respect to the project.

On January 10, 2023, Indiana Electric filed a CPCN with the IURC to acquire a wind energy generating facility with installed capacity of 200 MWs through a BTA, consistent with its 2019/2020 IRP that calls for up to 300 MWs of wind generation.

The wind project is located in MISO’s Central Region.

Indiana Electric received approval from the IURC to recover the costs of the wind facility via the CECA mechanism, which the developer believes can be placed in service by the end of 2026.

On June 6, 2023, the IURC issued an order approving the CPCN, thereby authorizing Indiana Electric to purchase the wind generating facility.

However, as of the date of the filing of this Form 10-K, Indiana Electric has not entered into any definitive agreement relating to this wind energy generating facility, and it is not certain that a definitive agreement will be entered into at all.

Indiana Electric also 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 provides equivalent equity return to offset imputed debt during the 25-year life of the PPA.

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.

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 were compelled to renegotiate terms of the agreement to increase the PPA price.

On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with certain modifications.

Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA.

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, the developer disclosed the project in-service date would be delayed to 2026.

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 interconnection study were completed, Origis advised Indiana Electric that the costs to construct the solar project in Knox County, Indiana had increased.

The increase was largely driven by 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 previously approved Knox County solar PPA with certain modifications.

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 will be delayed to 2026.

On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved Vermillion County solar PPA with Oriden with certain modifications.

Revised purchase power costs were approved to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden.

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 early 2026.

Natural Gas Combustion Turbines

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...”

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 estimated $334 million turbine facility is being constructed at the previous site of the A.B.

Brown power plant in Posey County, Indiana and is expected to provide a combined output of 460 MW.

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 will be constructed and operated by Texas Gas Transmission, LLC to supply natural gas to the turbine 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 the

FERC’s order granting the certificate.

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.

The facility is targeted to be operational by mid-year 2025.

On February 6, 2025, the EPC contractor for Indiana Electric’s proposed natural gas combustion turbines provided a notice to Indiana Electric that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project.

Recovery of the proposed natural gas combustion turbines and regulatory asset was included in the forecasted test year in the Indiana Electric rate case, which was filed with the IURC on December 5, 2023.

For more information on the Indiana Electric rate case, see “— Rate Change Applications” below.

For more information regarding uncertainties related to our solar projects, see Part I, Item 1A of this combined Form 10-K and “ —Solar Panel Issues” below.

Culley Unit 3 Operations

In June 2022, F.B.

Culley Unit 3, an Indiana Electric coal-fired electric generation unit with an installed generating capacity of 270 MW, experienced an operating issue relating to its boiler feed pump turbine.

The unit returned to service in March 2023.

In testimony filed September 13, 2023, the OUCC and an intervenor that represents industrial customers filed testimony with the IURC alleging that Indiana Electric did not act prudently which led to the unplanned outage and recommended disallowances between $21 million to $27 million.

On July 3, 2024, the IURC issued an order finding Indiana Electric acted reasonably and prudently with respect to the events that gave rise to the Culley Unit 3 outage and, in addition, did not approve the intervenors proposed disallowance.

The order is now final and non-appealable.

In the second quarter of 2025, 230 MW of the facility was

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)

2 unchanged sentences

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 half of 2026.

Kilgore Transmission Project (CenterPoint Energy and Houston Electric)

2 unchanged sentences

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 second quarter of 2026.

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)

2 unchanged sentences

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 first half of 2027.

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;

• apply a levelized billing plan to residential customers who are eligible and have applied for the Low Income Housing Energy Assistance Program;

• 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)

Houston Electric and CERC were affected by legislation passed in 2023 and associated PUCT rulemaking projects, including the following pieces of legislation that became law during the 88th Texas Legislature, including:

• House Bill 1500 became effective on September 1, 2023 and continues the functions of the PUCT, the Office of Public Utility Counsel, and ERCOT through 2029.

This bill also includes an amendment that clarifies the use cases under which TDUs may lease and operate temporary generation during “significant” power outages;

• House Bill 2263 became effective on June 12, 2023 and authorizes LDCs to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority;

• House Bill 2555 became effective on June 13, 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity, physical security, vegetation management and wildfire mitigation.

On January 18, 2024, the PUCT issued an Order adopting its Resiliency Plan Rule (16 Tex.

Code § 25.62);

• Senate Bill 947 became effective on September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages;

• Senate Bill 1015 became effective on June 18, 2023 and allows utilities to file the DCRF twice a year, on any day the PUCT is open (at least 185 days after filing a full base rate proceeding) and setting an administrative approval timeline of 60 days;

• Senate Bill 1016 became effective on May 5, 2023 and requires the PUCT to presume that all employee compensation and benefits are reasonable and necessary when establishing a utility’s rates if based upon market compensation studies issued within the last three years;

it includes exceptions for utility officer incentives that are based on financial metrics.

Certain incentive compensation that is in-line with market studies will be presumed reasonable and recoverable;

• Senate Bill 1076 became effective on June 2, 2023 and moves the timeline for the PUCT to approve CCN for transmission projects to 180 days after the date of filing, rather than the first anniversary of the day it was filed.

The Registrants will monitor the 89th Texas Legislature for legislation that may impact their businesses.

Minnesota Legislation (CenterPoint Energy and CERC)

The Natural Gas Innovation Act was passed by the Minnesota legislature in June 2021 with bipartisan support.

This law establishes a regulatory framework to enable the state’s investor-owned natural gas utilities to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions and advancing the state’s clean energy future.

The maximum allowable cost for an innovation plan will start at 1.75% of the utility's revenue in the state and could increase to 4% by 2033, subject to review and approval by the MPUC.

Specifically, the Natural Gas Innovation Act allows a natural gas utility to submit an innovation plan for approval by the MPUC that can propose the use of renewable energy resources and innovative technologies such as:

• renewable natural gas (produces energy from organic materials such as wastewater, agricultural manure, food waste, agricultural or forest waste);

• renewable hydrogen gas (produces energy from water through electrolysis with renewable electricity such as solar);

• energy efficiency measures (avoids energy consumption in excess of the utility’s existing conservation programs);

• innovative technologies (reduces or avoids GHG emissions using technologies such as carbon capture).

On June 28, 2023, CERC submitted its first innovation plan to the MPUC;

the five-year plan includes 18 pilot projects and seven smaller research-and-development projects.

These projects will deploy and evaluate a broad array of innovative resources including made-in-Minnesota alternative gases such as renewable natural gas and green hydrogen, as well as pioneering technologies such as a networked geothermal district energy system and end-use carbon capture.

The proposed plan requires approval from the MPUC through a review process that is expected to take about one year.

The MPUC requested comments by September 15, 2023 if parties believe that the filing is incomplete based on the reporting requirements or if parties do not believe that that the MPUC’s standard informal proceeding process is appropriate.

No parties filed comments regarding completeness or raising concerns that the MPUC’s standard informal procedural process is inappropriate.

The initial comment period closed on January 15, 2024, the reply comment period closed on March 15, 2024 and the supplemental comment period closed on May 15, 2024.

On July 25, 2024, the MPUC voted to approve the plan with some minor modifications during its agenda meeting and a formal order was issued on October 9, 2024.

Solar Panel Issues (CenterPoint Energy)

CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs.

The potential delays and inflationary cost pressures communicated from the developers of our solar projects have been primarily due to (i) unavailability of solar panels and other uncertainties related to DOC antidumping and countervailing duties investigation(s), (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues.

On May 15, 2024, based on a petition filed by the American Alliance for Solar Manufacturing Trade Committee, the DOC announced the

initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells from Cambodia, Malaysia, Thailand, and Vietnam.

On October 1, 2024, the DOC’s preliminary countervailing duty determination affirmed the petition and established preliminary duty rates.

A final determination is expected in the first quarter of 2025.

On November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates.

A final determination is expected in the second quarter of 2025.

These impacts could result in cost increases for certain projects, and such impacts may require that we seek additional regulatory review and approvals.

Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects.

For more information regarding potential delays, cancellations and supply chain disruptions, see “Part I, Item 1A.

Risk Factors— Risk Factors Affecting Operations — Electric Generation, Transmission and Distribution — Increases in the cost or...” in this report.

TDSIC 2.0 (CenterPoint Energy)

On May 24, 2023, Indiana Electric filed its petition and case-in-chief with the IURC requesting, among other things, approval of its five-year plan for transmission, distribution, and storage improvements (TDSIC Plan) and an order approving the TDSIC Plan was issued on December 27, 2023.

The approved five-year TDSIC Plan, covering the period January 1, 2024 through December 31, 2028, consists of approximately $454 million in proposed investments across seven different programs:

(1) Distribution 12kV Circuit Rebuild, (2) Distribution Underground Rebuild, (3) Distribution Automation, (4) Wood Pole Replacement, (5) Transmission Line Rebuild, (6) Substation Rebuild, and (7) Substation Physical Security.

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)

House Bill 2555, codified as Tex.

Code § 38.078, was passed by the 88th Texas Legislature in 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT to enhance the resiliency of the utility’s transmission system through at least one or more of the following measures:

hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity measures, physical security measures, vegetation management, and wildfire mitigation and response.

House Bill 2555 also allows an electric utility to establish a regulatory asset for distribution-related costs, including depreciation expense and carrying costs at the electric utility’s weighted average cost of capital, relating to the implementation of a transmission and distribution system resiliency plan.

On April 29, 2024, Houston Electric filed its first transmission and distribution system resiliency plan with the PUCT, which proposed to implement 25 resiliency measures over a three-year period.

On August 1, 2024, Houston Electric announced that it was withdrawing its application for approval of its transmission and distribution system resiliency plan in order to focus on addressing the impacts of Hurricane Beryl and accelerating preparedness and resiliency efforts for the remaining storm season.

The ALJ granted Houston Electric’s request for withdrawal of the transmission and distribution system resiliency plan on August 16, 2024.

Anticipated to benefit Houston Electric customers by saving approximately 1.3 billion customer minutes of interruption, the SRP proposes 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 proposes 39 resiliency-enhancing measures and a microgrid pilot program to be implemented over the three-year period.

The SRP has 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 is for transmission-related investments, and approximately $3.58 billion is for distribution-related investments.

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

1 unchanged sentence

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 cost of service adjustments (e.g., RSP and RRA), their decoupling mechanism (e.g., decoupling and SRC), and their energy efficiency cost trackers (e.g., CIP, DSMA, EECR, EECRF, EEFC and EEFR).

Texas Gas Rate Case.

On October 30, 2023, CERC filed an application with the Railroad Commission and municipal regulatory authorities to set new natural gas base rates that would be applied consistently across the approximately 1.9 million customers.

The need for a rate change was primarily driven by the 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.

A settlement agreement was filed on April 23, 2024.

The settlement agreement was approved by the Railroad Commission on June 25, 2024 and provides for a $5 million annual increase in current revenues and establishes a 9.80% ROE and a 60.61% equity ratio for future GRIP filings.

New rates became effective in December 2024.

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 is approximately 6.5% or $85 million for 2024 and an additional approximately 3.7% or $52 million for 2025.

The need for a rate change is primarily driven by the 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 reflects a proposed 10.3% ROE on a 52.5% equity ratio.

The requested increase was for approximately

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.

The settlement provided for an increase of $60.8 million for 2024 and an additional $42.7 million for 2025.

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 Administrative Law Judge filed a report on February 13, 2025 recommending the Commission approve the settlement agreement.

The anticipated decision date of the rate case is July 1, 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 is approximately 16% or $119 million based on a forward looking 2025 test year.

The need for a rate increase is primarily driven by the continuing investment in the safety and reliability of the system and normal increases in operating expenses.

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 reflects a proposed 9.8% ROE on a forecasted 55% equity ratio.

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 approves the 9.8% ROE on a forecasted 55% equity ratio and increases revenues by $80 million.

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 is 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 is primarily driven by the 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 reflects 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 current rates.

On January 15, 2025, Houston Electric filed a letter indicating that an agreement in principle had been reached with certain parties and that complete settlement documents would be filed as soon as possible.

On January 29, 2025, Houston Electric announced that a settlement agreement was reached with certain parties to the rate case filed on March 6, 2024, including the City of Houston and other regional municipalities.

Subject to PUCT review and approval, the settlement is expected to result in approximately $50 million less annual revenue and an average decrease of approximately $1 a month for residential customers based on average usage of 1,000 kWh per month.

A proposed order was issued on February 10, 2025.

The parties must file corrections or exceptions to the proposed order by February 24, 2025.

Ohio Capital Expenditure Program (CEP).

On March 1, 2024, CEOH filed an application with the PUCO for authority to modify its CEP rates and charges.

The requested increase is approximately $3 million resulting in a proposed CEP rate for residential customers of $1.54 per month.

Per the PUCO’s Opinion and Order in the 2018 general rate case, the CEP rate is capped at $1.50 per month for residential customers.

CEOH requested deferral of the 2023 CEP revenue requirement above the CEP rate cap of approximately $155,000.

CEOH filed a statement of resolution on July 30, 2024, indicating CEOH and PUCO staff agree to certain statements including:

CEOH’s existing deferral authority has not expired and will continue uninterrupted, provided CEOH files its notice of intent for its base rate case prior to the new CEP Rider charges taking effect.

PUCO issued a Finding & Order on August 21, 2024, finding that the parties’ resolution of the rate cap and deferral authority issues were reasonable.

As discussed below, notice of intent for a base rate case was filed the following week.

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 .

On August 27, 2024, CEOH filed a Notice of Intent with PUCO to begin the process of requesting an adjustment in natural gas base rates.

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 return on equity of 10.4% and equity percentage of 45.87%.

The need for a rate increase is primarily driven by the continuing investment in the safety and reliability of the natural gas system.

A final order is expected no sooner than the first quarter of 2026.

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

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:

Mechanism Annual Increase (1)

(in millions)

Mechanism Annual Increase (Decrease) (1)

(in millions) Filing

Date Effective Date Approval Date Additional Information

CenterPoint Energy and Houston Electric (PUCT)

December 2023

Based on the net change in distribution invested capital since its last base rate proceeding of approximately $2.5 billion for the period January 1, 2019 through September 30, 2023, of which $672 million is incremental to the previous DCRF filing, for an incremental revenue increase of $86 million, adjusted for load growth.

On February 5, 2024, Houston Electric notified the ALJ that the parties reached an agreement in principle on all issues in this proceeding and filed an agreed expedited motion for interim rates.

On February 13, 2024, interim rates designed to collect $220 million ($73 million incremental) were approved by the ALJ, to be effective April 2024.

A final order was issued by the PUCT March 7, 2024.

Rate Case $ (47) March 2024

See discussion above under Houston Electric Rate Case .

TCOS $ 64 February 2025

Based on the net change in invested capital since its last base rate proceeding of approximately $614 million for the period January 1, 2024 through December 31, 2024.

DCRF $ 123 February 2025

Based on the net change in distribution invested capital since its last base rate proceeding of approximately $1 billion for the period January 1, 2024 through December 31, 2024, for an incremental revenue increase of $123 million adjusted for load growth.

TEEEF $ (24) April 2025

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 release the five medium 5.7 MW TEEEF units from its TEEEF fleet and remove the associated lease costs effective January 1, 2026.

On February 13, 2026, Houston Electric filed a letter requesting continued abatement until February 27, 2026 due to continued settlement discussions.

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 January 6, 2026, Houston Electric provided the PUCT with a proposed order.

EECRF $ 40 May 2025

December 2025

The requested $65 million is comprised primarily of the following:

Requests $96 million, which is comprised primarily of the following:

2026 program costs of $50 million;

a credit of $0.5 million related to the over-recovery of 2023 program costs;

$5 million related to the under-recovery of 2024 program costs;

the 2024 earned bonus of $40 million;

and 2026 projected evaluation, measurement and verification costs of $0.6 million.

On October 17, 2024, a unanimous settlement was filed for an adjusted total of $63 million, keeping the 2023 earned bonus of $15 million.

A final order approving the settlement was issued on December 12, 2024.

November 2024

Based on net change in invested capital of $517 million for the period July 2023 through September 2024.

Notice of Approval was issued by PUCT January 13, 2025.

CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)

On September 8, 2025, the Sierra Club filed direct testimony.

On September 19, 2025, the PUCT staff filed its recommendation requesting that SOAH approve the application as filed.

On October 3, 2024, the PUCT staff petitioned (Docket No.

57172) to establish a secondary cap on utilities’ 2024 Program Year (PY) earned performance bonuses equal to 25% of utilities’ total expenditures for PY 2024, and on August 13, 2025, the PUCT issued a final order denying the PUCT staff’s petition.

On October 7, 2025, Houston Electric filed an unanimous stipulation and settlement agreement for the full amount requested.

On October 10, 2025, SOAH remanded this proceeding to the PUCT.

A final order approving the settlement agreement was issued on December 12, 2025.

TCOS $ 15 August 2025

Based on the net change in invested capital since its last TCOS proceeding of approximately $112 million for the period January 1, 2025 through June 30, 2025.

DCRF $ 55 August 2025

December 2025

See discussion above under Texas Gas Rate Case.

Tax Act Rider

Based on the net change in distribution invested capital since its last base rate proceeding of approximately $1.5 billion for the period January 1, 2024 through June 30, 2025 for an incremental revenue increase of $55 million adjusted for load growth.

Mechanism Annual Increase (Decrease) (1)

(in millions) Filing

Date Effective Date Approval Date Additional Information

$ 36 February 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.

CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)

Tax Act Rider $ 15 August 2024

Resulting from the Texas Gas Rate Case, the first Tax Act Rider Calculation was filed on August 1, 2024 pursuant to Docket No.

OS-23-00015513 to recover the effects of the Inflation Reduction Act (“Tax Act 2022”) and certain other tax-related costs for rates to become effective January 1, 2025.

These effects include the return on the CAMT deferred tax asset (“DTA”) resulting from the Tax Act 2022, income tax credits resulting from the Tax Act 2022, and the return on the increment or decrement in the NOL DTA included in rate base and in the standard service base revenue requirement approved in the Texas Gas Rate Case.

OS-23-00015513 to recover the effects of the IRA and certain other tax-related costs for rates that became effective January 1, 2025.

These effects include the return on the CAMT deferred tax asset (“DTA”) resulting from the IRA, income tax credits resulting from the IRA and the return on the increment or decrement in the net operating loss DTA included in the rate base and in the standard service base revenue requirement approved in the Texas Gas Rate Case.

CERC believes its filing is consistent with the Tax Act Rider tariff approved in Docket No.

2 unchanged sentences

Briefings were filed with an ALJ in November 2024.

A hearing on the merits will be held on February 21, 2025.

A hearing on the merits was held on February 21, 2025 and continued on March 21, 2025.

On March 21, 2025, a unanimous settlement agreement was filed.

On April 11, 2025, a PFD was issued.

On May 13, 2025, the Railroad Commission considered the PFD at an open meeting and issued a Final Order approving the settlement agreement.

Tax Act Rider $ 22 August 2025

The second Tax Act Rider was initially filed on August 1, 2025, and a revised filing was made on September 24, 2025, to recover the effects of the IRA and certain other tax-related costs for rates that would be effective for bills calculated on or after January 1, 2026.

These effects include the return on the CAMT DTA resulting from the IRA, income tax credits resulting from the IRA and the return on the increment or decrement in the net operating loss DTA included in the rate base and in the standard service base revenue requirement approved in the Texas Gas Rate Case Docket No.

OS-23-00015513.

No comments from the parties were filed prior to the October 1, 2025 deadline for comments.

The Railroad Commission accepted the Tax Act Rider filing on October 16, 2025.

GRIP $ 70 February 2025

Based on net change in invested capital of $445 million.

$ 62 February 2026

Based on net change in invested capital of $394 million.

Mechanism Annual Increase (1)

(in millions)

Date Effective Date Approval Date Additional Information

CenterPoint Energy and CERC - Minnesota (MPUC)

CIP Financial Incentive

Rate Case $ 104 November 2023

September 2025 July 2025

See discussion above under Minnesota Gas Rate Case.

CIP Financial Incentive $ 8 May 2025

December 2025

1 unchanged sentence

CIP Financial Incentive based on 2024 CIP program activity.

November 2023

See discussion above under Minnesota Gas Rate Case.

CenterPoint Energy and CERC - Louisiana (LPSC)

September/October 2023

Based on ROE of 9.95% with 50 basis point (+/-) earnings band.

The North Louisiana increase, net of TCJA effects considered outside of the earnings band and completion of COVID-19 asset recovery, is $8 million based on a test year ended June 2023 and adjusted ROE of 3.67%.

The South Louisiana increase, net of TCJA effects considered outside of the earnings band and completion of COVID-19 asset recovery, is $5 million based on a test year ended June 2023 and adjusted ROE of 5.47%.

The TCJA refund impact to North Louisiana and South Louisiana was $0.6 million and $0.4 million, respectively.

South Louisiana interim rates were implemented on December 28, 2023, subject to refund.

North Louisiana interim rates were implemented on January 29, 2024.

Staff reports issued on January 31, 2024 recommended disallowances of $0.3 million and $0.2 million in North and South Louisiana, respectively.

LPSC voted to approve the January 2024 staff reports on April 19, 2024.

Implementation occurred in June 2024.

Based on ROE of 9.95% with 50 basis point (+/-) earnings band.

The North Louisiana increase, inclusive of TCJA effects considered outside of the earnings band, is $7 million based on a test year ended June 2024 and adjusted ROE of 5.56%.

The South Louisiana increase, inclusive of TCJA effects considered outside of the earnings band, is $6 million based on a test year ended June 2024 and adjusted ROE of 5.96%.

Interim rates, subject to refund, were implemented December 19, 2024.

CenterPoint Energy and CERC - Mississippi (MPSC)

September 2024

Based on ROE of 10.263% with 100 basis points (+/-) earnings band.

Revenue increase of approximately $11 million based on 2023 test year adjusted earned ROE of 5.11%.

Interim increase of approximately $1.3 million implemented May 31, 2024.

On September 5, 2024, MPSC approved a settlement revenue adjustment of $9.4 million.

CenterPoint Energy - Indiana South - Gas (IURC)

Requested an increase of $35 million to rate base, which reflects approximately $3.6 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 $0.03 million annually.

The final IURC order was issued July 31, 2024, approving CSIA rates as proposed effective August 1, 2024.

CSIA $ 2 April 2025

Requested an increase of $11.6 million to rate base, which reflects an approximately $1.5 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 $1.9 million.

The OUCC filed testimony on June 3, 2025, recommending minor changes.

Indiana South filed a rebuttal on June 17, 2025, adopting the changes.

The evidentiary hearing was held on June 30, 2025.

A final order was issued on July 30, 2025, with rates effective August 1, 2025.

CSIA $ 1 October 2025

February 2026

Requested an increase of $18 million to rate base, which reflects approximately $2.4 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 $(1.0) million annually.

The final IURC order was issued January 29, 2025 approving rates as filed with the correction filing effective February 1, 2025.

Mechanism Annual Increase (1)

(in millions)

Date Effective Date Approval Date Additional Information

Requested an increase of $13.0 million to rate base, which reflects an approximately $1.2 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 $(2.1) million.

The OUCC filed testimony on December 2, 2025, recommending minor changes, and Indiana South filed rebuttal on December 16, 2025.

An evidentiary hearing was held January 6, 2026.

A final order was issued on January 28, 2026 with rates effective on February 1, 2026.

CenterPoint Energy and CERC - Indiana North - Gas (IURC)

Requested an increase of $97 million to rate base, which reflects approximately $9.4 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 $1 million annually.

The final IURC Order was issued July 31, 2024, approving CSIA rates as proposed effective August 1, 2024.

CSIA $ 9 April 2025

Requested an increase of $94.9 million to rate base, which reflects an approximately $8.6 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 $5 million.

The OUCC filed testimony on June 3, 2025.

Indiana North filed rebuttal testimony on June 17, 2025.

The evidentiary hearing was held on June 30, 2025.

A final order was issued on July 30, 2025, with rates effective August 1, 2025.

Mechanism Annual Increase (Decrease) (1)

(in millions) Filing

Date Effective Date Approval Date Additional Information

CSIA $ 8 October 2025

February 2026

Requested an increase of $84 million to rate base, which reflects approximately $11.0 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 $(3.0) million annually.

The final IURC order was issued January 29, 2025, approving rates as filed with the correction filing effective February 1, 2025.

Requested an increase of $90.8 million to rate base, which reflects an approximately $7.6 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 $(6.8) million.

The OUCC filed testimony on December 2, 2025, recommending minor changes, and Indiana North filed rebuttal on December 16, 2025.

An evidentiary hearing was held January 6, 2026.

A final order was issued on January 28, 2026, with rates effective on February 1, 2026.

On February 17, 2026, the OUCC filed a motion for rehearing and reconsideration requesting the commission to reconsider its decision approving the recovery of soil remediation costs from ratepayers and reconsider the threshold for a best estimate for a TDSIC plan and the specific justification the commission will require to increase an approved best estimate.

CenterPoint Energy and CERC - Ohio - Gas (PUCO)

See discussion above under Ohio Capital Expenditure Program.

September 2024

September 2025 August 2025

Requested an increase of $54 million to rate base for investments made in 2024, which reflects a $6 million annual increase in current revenues.

A change in (over)/under-recovery variance of ($0.03) million annually is also included in rates.

PUCO Opinion & Order was issued August 21, 2024, approving DRR rates as proposed.

Revised rates became effective September 1, 2024.

PUCO staff and intervenor (Ohio Consumers’ Counsel) filed comments June 27, 2025.

PUCO staff recommended approval.

Ohio Consumers’ Counsel commented on affordability and provided potential solutions including stretching out the replacement program over a longer period of time, phasing in the annual increase, shifting from fixed charges to volumetric charges, and increasing funding for its bill assistance programs.

A statement informing the PUCO of whether the issues raised in comments have been resolved was filed on July 11, 2025.

Supplemental Testimony from CEOH and the Ohio Consumers’ Counsel was filed on July 22, 2025.

A hearing was scheduled for July 29, 2025, with all parties waiving motions to strike, objections, and cross examination.

A final PUCO opinion and order was issued on August 20, 2025, finding that the updated DRR rates are just and reasonable and stating that the correct forum for the Ohio Consumers’ Counsel’s arguments was the 2018 Rate Case, the 2022 Extension, or the 2024 Rate Case.

Revised rates became effective on September 1, 2025.

Rate Case $ 51 October 2024

See discussion above under Ohio Gas Rate Case.

CenterPoint Energy - Indiana Electric (IURC)

80 December 2023

February 2025

See discussion above under Indiana Electric Rate Case.

5 February 2024

Requested an increase of $36 million to rate base, which reflects a $5 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until next rate case.

An order approving the request was issued on May 17, 2024 and was effective May 16, 2024.

— February 2024

Requested a decrease of $1 million to rate base, which reflects no change in current revenues.

The mechanism also includes a change in (over)/under-recovery variance of $0.1 million.

The final order was issued May 29, 2024, approving rates effective June 1, 2024.

Requested an increase of $48 million to rate base, which reflects a $6 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until next rate case.

The mechanism also includes a reduction in the under-recovery variance of $1 million.

The OUCC filed testimony on July 1, 2024 recommending approval.

A final order approving the request was issued on August 28, 2024.

5 August 2024

November 2024

Requested an increase of $30 million to rate base, which reflects a $5 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case.

The final order was issued on November 27, 2024 approving rates effective November 28, 2024.

(1) Represents proposed increases when effective date and/or approval date is not yet determined.

(1) Represents proposed increases (decreases) when effective date and/or approval date is not yet determined.

Approved rates could differ materially from proposed rates.

Inflation Reduction Act (IRA)

On August 16, 2022, the IRA was signed into law.

The law extends or creates tax-related energy incentives for solar, wind and alternative clean energy sources, implements, subject to certain exceptions, a 1% tax on share repurchases after December 31, 2022, and implements a 15% CAMT based on the adjusted financial statement income of certain large corporations.

Corporations are entitled to a CAMT credit to the extent CAMT liability exceeds regular tax liability, which can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.

The Registrants will owe CAMT in excess of their regular tax liability beginning in 2024.

As a result, the Registrants may experience a temporary increase in federal cash tax liability due to this provision beginning in 2024.

On September 12, 2024, the IRS issued proposed regulations addressing the application of the CAMT.

The proposed regulations offer guidance for computing an entity’s adjusted financial statement income, in addition to addressing other provisions of the CAMT.

At this time, the Company does not anticipate changes to the applicability of CAMT to the Registrants as a result of the proposed regulations.

For more information regarding changes in federal income tax laws and regulations and our related risks, see Part I, Item 1A.

“Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — We may be significantly affected by changes in federal income tax laws and regulations...”

Greenhouse Gas Regulation and Compliance (CenterPoint Energy)

CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of reducing the consumption of natural gas.

Additionally, the Methane Emissions Reduction Program established by the IRA and the new regulations published by the EPA on March 8, 2024 targeting reductions in methane emissions, may increase costs related to production, transmission and storage of natural gas.

Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity.

Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within their respective service territories.

Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services.

Further, requirements and/or incentives to reduce energy consumption by certain specified dates in the Registrants’ respective service areas could have a significant impact on CenterPoint Energy and its operations.

Further, our third-party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact CenterPoint Energy’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to CenterPoint Energy.

Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to benefit CenterPoint Energy and CERC and their natural gas-related businesses.

At this time, however, we cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Registrants’ businesses.

Additionally, the Registrants continue to evaluate the impact of the final rules adopted by the SEC on March 6, 2024 regarding disclosure of certain climate-related information in registration statements and annual reports, for which implementation is subject to ongoing voluntary delay by the SEC, on their respective consolidated financial statements and related disclosures.

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.

Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain;

2 unchanged sentences

Currently, CenterPoint Energy does not purchase carbon credits.

In connection with its net zero emissions goals, CenterPoint Energy is expected to purchase carbon credits in the future;

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.

For more information on greenhouse gas and climate-change regulation and compliance, see “Business—Environmental Matters” in Item 1 of Part I of this report.

Climate Change Trends and Uncertainties

As a result of increased attention regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Registrants’ services.

As these technologies likely become more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Registrants’ systems and

services, which may result in, among other things, Indiana Electric’s generating facilities becoming less competitive and economical.

Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on CenterPoint Energy’s electric generation and natural gas businesses.

For example, because Indiana Electric currently relies on coal for a portion of its generation capacity, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements.

Conversely, demand for the Registrants’ services may increase as a result of customer changes in response to climate change.

For example, the expected expansion of energy export facilities, including hydrogen facilities, and electrification of industrial processes and transport and logistics, among others, in our service territories could lead to an increase in demand for electricity, resulting in increased usage of CenterPoint Energy’s systems and services.

Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation.

To address these developments, CenterPoint Energy announced its net zero emission goals for Scope 1 and certain Scope 2 emissions by 2035 and a 20-30% reduction in certain Scope 3 emissions by 2035 as compared to 2021 levels.

Indiana Electric’s 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation.

Indiana Electric continues to execute on its 2019/2020 IRP and has received initial approvals for 626 MWs of the 700-1,000 MWs of solar generation and 200 MWs of the 300 MWs of wind generation identified within Indiana Electric’s 2019/2020 IRP through a combination of BTAs and PPAs.

Additionally, as reflected in its 10-year capital plan announced in September 2021, CenterPoint Energy anticipates spending over $3 billion in cleaner energy investments and enablement, which may be used to support, among other things, renewable energy generation.

CenterPoint Energy believes its planned investments in renewable energy generation and corresponding planned reduction in its Scope 1 and certain Scope 2 emissions as part of its net zero emissions goals, as well as its planned reduction in Scope 3 emissions by 20-30% by 2035 as compared to 2021 levels, support global efforts to reduce the impacts of climate change.

Indiana Electric has conducted a new IRP, which was submitted to the IURC in May 2023, to identify an appropriate generation resource portfolio to satisfy the needs of its customers and comply with environmental regulations.

The proposed preferred portfolio is the second evolution to the generation transition plan to move away from coal-fired generation to a more sustainable portfolio of resources.

Under the proposed preferred portfolio, Indiana Electric plans to convert its last remaining coal unit to natural gas and to add a significant amount of additional renewable resources through 2033.

Indiana Electric has since received approval for 147 MWs of wind generation facilities identified within Indiana Electric’s 2022/2023 IRP through a PPA.

For more information regarding CenterPoint Energy’s net zero and GHG emissions reduction goals and the risks associated with them, see Part I, Item 1A.

“Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks...” For more information on Indiana Electric’s IRP and associated risks, see Part I, Item 1A.

“Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — Indiana Electric’s execution of its generation transition plan...”

To the extent climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted.

For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales.

On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity used for cooling.

Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes, floods, microbursts, severe winter weather conditions, including ice storms, wildfires, thunderstorms, high winds, hail, derecho events, or extreme temperatures, including such storms as the February 2021 Winter Storm Event, the May 2024 Storm Events and Hurricane Beryl.

Since many of the Registrants’ facilities are located along or near the Texas Gulf Coast, increased or more severe weather events could increase costs to repair damaged facilities and restore service to customers.

CenterPoint Energy’s current 10-year capital plan includes capital expenditures to maintain reliability and safety and increase resiliency of its systems as climate change may result in more frequent significant weather events.

Houston Electric does not own or operate any electric generation facilities other than, since September 2021, its operation of TEEEF.

Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties.

To the extent adverse weather conditions affect the Registrants’ suppliers, results from their energy delivery businesses may suffer.

For example, in Texas, the February 2021 Winter Storm Event caused an electricity generation shortage that was severely disruptive to Houston Electric’s service territory and the wholesale generation market and also caused a reduction in available natural gas capacity.

Additionally, the May 2024 Storm Events and Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in electric service interruptions peaking at an estimated 922,000 customers and more than 2.1 million customers, respectively.

When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs.

To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted.

Further, as the

intensity and frequency of significant weather events continues, it may impact our ability to secure cost-efficient insurance.

For more information regarding risks relating to climate change and other weather and natural disaster impacts, see Part I, Item 1A.

“Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — Climate change and other weather and natural disaster impacts could...”

For more information on GHG emissions and climate-change regulation and compliance, see “Business—Environmental Matters” in Item 1 of Part I of this report.

For more information on GHG emissions and climate-related risk trends and uncertainties, see “Risk Factors” in Item 1A of Part I of this report.

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.

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.

For more information on climate risk trends and uncertainties, see “Risk Factors” in Item 1A of Part I of this report.

Other Matters

20 unchanged sentences

Each of the Registrant’s credit facilities provide for a mechanism to replace SOFR with possible alternative benchmarks upon certain benchmark replacement events.

The borrowers are currently in compliance with the various business and financial covenants in the four revolving credit facilities.

The Registrants and SIGECO are currently in compliance with the various business and financial covenants in the four revolving credit facilities.

Debt Transactions

For detailed information about the Registrants’ debt transactions in 2025, see Note 12 to the consolidated financial statements.

For detailed information about the delay draw term loan agreement executed by CERC Corp.

in 2026, see Note 20 to the consolidated financial statements.

Securities Registered with the SEC

2 unchanged sentences

For information related to the Registrants’ debt issuances in 2025, see Note 12 to the consolidated financial statements.

Temporary Investments

As of February 10, 2025, the Registrants had no temporary investments.

For information related to shares of Common Stock sold pursuant to the forward sale agreements and the Equity Distribution Agreement in 2025, see Note 11 to the consolidated financial statements.

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.

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.

4 unchanged sentences

Money pool borrowings 3.80% $ 463 $ —

4.56% $ 58 $ —

Impact on Liquidity of a Downgrade in Credit Ratings

3 unchanged sentences

Registrant Borrower/Instrument Rating Outlook (1) Rating Outlook (2) Rating Outlook (3)

CenterPoint Energy CenterPoint Energy Senior Unsecured Debt Baa2 Negative BBB Negative BBB Negative

CenterPoint Energy CenterPoint Energy Senior Unsecured Debt Baa2 Negative BBB Stable

CenterPoint Energy Vectren Corp.

Issuer Rating n/a Negative BBB+ Negative n/a n/a

CenterPoint Energy SIGECO Senior Secured Debt A1 Stable A Negative n/a n/a

Houston Electric Houston Electric Senior Secured Debt A2 Negative A Negative A Negative

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+ Negative A- Negative

CERC Indiana Gas Senior Unsecured Debt n/a n/a BBB+ Negative n/a n/a

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.

11 unchanged sentences

If the credit ratings of CERC Corp.

decline below the applicable threshold levels,

CERC might need to provide cash or other collateral of as much as $159 million as of December 31, 2024.

decline below the applicable threshold levels, CERC might need to provide cash or other collateral of up to $311 million as of December 31, 2025.

The amount of collateral will depend on seasonal variations in transportation levels.

2 unchanged sentences

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 cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold.

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 significant 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 December 31, 2024, deferred taxes of approximately $802 million would have been payable in 2024.

If all the ZENS-Related Securities had been sold on December 31, 2024, capital gains taxes of approximately $84 million would have been payable in 2024 based on 2024 tax rates in effect.

If all ZENS had been exchanged for cash on December 31, 2025, deferred taxes of approximately $897 million would have been payable in 2025, subject to reduction on account of any available net operating loss carryforwards or CAMT carryforwards.

If all the ZENS-Related Securities had been sold on December 31, 2025, capital gains taxes of approximately $72 million would have been payable in 2025 based on 2025 tax rates in effect and subject to reduction on account of any available net operating loss carryforwards or CAMT carryforwards.

As of December 31, 2025, 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 10 to the consolidated financial statements.

Cross Defaults

Under the Registrants’ respective revolving credit facilities and any term loan agreements (in each case, other than SIGECO), 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 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.

5 unchanged sentences

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.

CenterPoint Energy has increased its planned capital expenditures in its Electric and Natural Gas businesses multiple times over the recent years to support rate base growth and may continue to do so 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.

As announced in September 2025 and February 2026, CenterPoint Energy has increased its planned capital expenditures in its Electric and Natural Gas businesses pursuant to its new 10-year capital plan, which calls for investment of at least $65.5 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, in addition to the completed sale of CERC Corp.’s Louisiana and Mississippi natural gas LDC businesses, 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 4 to the consolidated financial statements.

On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses.

The transaction is expected to close in the first quarter of 2025.

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 4 to the consolidated financial statements.

4 unchanged sentences

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’s 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.

In the event of a REP’s 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

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.

7 unchanged sentences

• 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 or regulatory actions, including such actions in response 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 (CenterPoint Energy and CERC);

• the satisfaction of any obligations pursuant to guarantees;

13 unchanged sentences

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.

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 management believes the following accounting policies involve the application of critical accounting estimates.

Accordingly, these accounting estimates

have been reviewed and discussed with the Audit Committee of CenterPoint Energy’s Board of Directors.

Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board.

For a complete discussion of the Registrants’ significant accounting policies, see Note 2 to the consolidated financial statements.

22 unchanged sentences

Assets Held for Sale

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell, and a sale is expected to be completed within one year.

The Registrants record assets and liabilities held for sale, or the disposal group, at the lower of their carrying value or their estimated fair value less cost to sell.

If the disposal group reflects a component of a reporting unit and meets the definition of a business,

the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed.

Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board, as applicable, commits to a plan to sell, and a sale is expected to be completed within one year.

The Registrants

record assets and liabilities held for sale, or the disposal group, at the lower of their carrying value or their fair value less cost to sell.

If the disposal group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed.

Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business.

As described further in Note 4 to the consolidated financial statements, certain assets and liabilities of the Louisiana and Mississippi natural gas LDC businesses met the held for sale criteria and the goodwill attributable to these businesses as of December 31, 2024 was $217 million and $122 million for CenterPoint Energy and CERC, respectively.

Accounting for Securitization of Coal Generation Facility Retirements

As of December 31, 2025, certain assets and liabilities of the Ohio natural gas LDC business met the held for sale criteria and the goodwill attributable to these businesses was $393 million and $219 million for CenterPoint Energy and CERC, respectively.

As of December 31, 2024, certain assets and liabilities of the Louisiana and Mississippi natural gas LDC businesses met the held for sale criteria and the goodwill attributable to these businesses was $217 million and $122 million for CenterPoint Energy and CERC, respectively.

See Note 4 for additional detail.

Accounting for Securitizations

Accounting guidance for rate regulated long-lived asset abandonment requires that the carrying value of an operating asset or an asset under construction is removed from property, plant and equipment when it becomes probable that the asset will be abandoned.

4 unchanged sentences

Determining probability of abandonment or probability of recovery requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals.

In connection with the securitization financing of qualified costs in the second quarter of 2023 associated with the completed retirement of SIGECO’s A.B.

Brown coal generation facilities, CenterPoint Energy evaluated the VIE consisting of the SIGECO Securitization Subsidiary, a wholly-owned, bankruptcy-remote, special purpose entity, for possible consolidation, including review of qualitative factors such as the power to direct the activities of the VIE and the obligation to absorb losses of the VIE.

CenterPoint Energy has the power to direct the significant activities of the VIE and is most closely associated with the VIE as compared to other interests held by the holders of the SIGECO Securitization Bonds.

CenterPoint Energy is, therefore, considered the primary beneficiary and consolidated the VIE.

For purposes of reporting cash flows, the Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase.

Cash and cash equivalents held by the SIGECO Securitization Subsidiary solely to support servicing the SIGECO Securitization Bonds as of December 31, 2024 are reflected on CenterPoint Energy’s Consolidated Balance Sheet.

In connection with the issuance of the SIGECO Securitization Bonds, CenterPoint Energy was required to establish a restricted cash account to collateralize the SIGECO Securitization Bonds that were issued in the financing transaction.

The restricted cash account is not available for withdrawal until the maturity of the SIGECO Securitization Bonds and is not included in cash and cash equivalents.

In connection with the securitization of transition property or system restoration property or to facilitate the securitization financing of qualified costs, CenterPoint Energy, Houston Electric and SIGECO evaluate the wholly-owned, bankruptcy-remote, special purpose entities, which are VIEs, for possible consolidation, including review of qualitative factors such as the power to direct the activities of the VIE and the obligation to absorb losses of the VIE.

CenterPoint Energy, Houston Electric and SIGECO have the power to direct the significant activities of their respective VIEs and are most closely associated with their respective VIEs as compared to other interests held by the holders of the relevant Securitization Bonds.

CenterPoint Energy, Houston Electric and SIGECO are, therefore, considered the respective primary beneficiary and consolidate these VIEs.

Unbilled Revenues

10 unchanged sentences

CenterPoint Energy uses several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to its plans.

These factors include assumptions about the discount rate, expected

return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines.

These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines.

In addition, CenterPoint Energy’s actuarial consultants use subjective factors such as withdrawal and mortality rates.

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants.

These differences may result in a significant impact to the amount of pension and other retirement plans expense recorded.

These differences may result in a significant impact to the

amount of pension and other retirement plans expense recorded.

Read “— Other Significant Matters — Pension Plans” for further discussion.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2(q) to the consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect the Registrants.

See Note 2(p) to the consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect the Registrants.

OTHER SIGNIFICANT MATTERS

5 unchanged sentences

Additionally, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans which allow participants to receive the benefits to which they would have been entitled under the non-contributory qualified pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.

CenterPoint Energy’s funding requirements and employer contributions for the years ended December 31, 2024, 2023 and 2022 were as follows:

CenterPoint Energy’s funding requirements and employer contributions were as follows for the periods presented:

Year Ended December 31,

9 unchanged sentences

The projected benefit obligation for all defined benefit pension plans was $1.5 billion as of December 31, 2025 and 2024, respectively.

The impacts resulting from increases in discount rates were offset by the changes in demographic and expected versus actual returns on assets.

The projected benefit obligation remained generally consistent from December 31, 2024 to December 31, 2025 as impacts resulting from the decrease in discount rates were offset by actual return on plan assets exceeding expected return on plan assets.

As of December 31, 2025, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $272 million.

Changes in interest rates or the market values of the securities held by the plan during

a year could materially, positively or negatively, change the funded status and affect the level of pension expense and required contributions at the next remeasurement.

Changes in interest rates or the market values of the securities held by the plan during a year could materially, positively or negatively, change the funded status and affect the level of pension expense and required contributions at the next remeasurement.

Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees.

8 unchanged sentences

Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.

As of December 31, 2024, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 7.00%, which is 50 basis points higher than the 6.50% rate assumed as of December 31, 2023.

As of December 31, 2025, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 7.00%, which is the same as the 7.00% rate assumed as of December 31, 2024.

The expected rate of return assumption was developed using the targeted asset allocation of our plans and the expected return for each asset class.

CenterPoint Energy regularly reviews its actual asset allocation and periodically rebalances plan assets to reduce volatility and better match plan assets and liabilities.

As of December 31, 2024, the projected benefit obligation was calculated assuming a discount rate of 5.60%, which is 65 basis points higher than the 4.95% discount rate assumed as of December 31, 2023 attributed primarily to rising interest rates.

As of December 31, 2025, the projected benefit obligation was calculated assuming a discount rate of 5.35%, which is 25 basis points lower than the 5.60% discount rate assumed as of December 31, 2024 attributed primarily to rising interest rates.

The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of CenterPoint Energy’s plans.

9 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis