CENTERPOINT ENERGY INC 10-K

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following combined discussion and analysis should be read in combination with the consolidated financial statements included in Item 8 herein. The discussion of CenterPoint Energy’s consolidated financial information includes the results of CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp., which, along with CenterPoint Energy, Inc., are collectively referred to as the Registrants. Where appropriate, information relating to a specific registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this combined Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric and CERC, unless 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. OVERVIEW Background CenterPoint Energy is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution systems. For a detailed description of CenterPoint Energy’s operating subsidiaries, see Note 1 to the consolidated financial statements. Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy, which provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas Gulf Coast area that includes the city of Houston. CERC Corp. 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. For further information, see Note 4 to the consolidated financial statements. Reportable Segments We discuss our operating results on a consolidated basis and individually for each of our reportable segments. We are first and foremost an energy delivery company and it is our intention to remain focused on these regulated segments. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject, among other factors. Below is a summary of CenterPoint Energy’s reportable segments as of December 31, 2024. For a detailed description of the assets included in each reporting segment, see Part I, Item 1. Business. • 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; (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. 49 • 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; and (iii) office buildings and other real estate used for business operations. Houston Electric and CERC each consist of a single reportable segment. EXECUTIVE SUMMARY We expect our businesses to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. Factors Influencing Our Businesses and Industry Trends We are an energy delivery company with electric transmission and distribution, power generation, and natural gas distribution operations that serve more than seven million metered customers across six jurisdictions. 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. 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 50 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. 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. 51 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...” 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. 52 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. For further information, see Note 11 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. For further information, see Note 4 to the consolidated financial statements. Regulatory Proceedings. 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 53 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. CERTAIN FACTORS AFFECTING FUTURE EARNINGS Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors that apply to all Registrants unless otherwise indicated including: • The business strategies and strategic initiatives, restructurings, joint ventures and acquisitions or dispositions of assets or businesses involving us or our industry, including the ability to successfully complete such strategies, initiatives, transactions or plans on the timelines we expect or at all, such as the announced sale of our 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; • non-payment for our services due to financial distress of our customers and the ability of our customers, including REPs, to satisfy their obligations to CenterPoint Energy, Houston Electric and CERC, and the negative impact on such ability related to adverse economic conditions and severe weather events; • public health threats, and their effect on our operations, business and financial condition, our industries and the communities we serve, U.S. and world financial markets and supply chains, potential regulatory actions and changes in customer and stakeholder behavior relating thereto; • 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 54 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; • 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; • 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; • 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; • 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; • the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl; • the effect of changes in and application of accounting standards and pronouncements; and • other factors discussed in “Risk Factors” in Part I, Item 1A of this report and in other reports that the Registrants file from time to time with the SEC. 55 56 CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS CenterPoint Energy’s results of operations are affected by seasonal fluctuations in the demand for electricity and natural gas. CenterPoint Energy’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates its subsidiaries charge, debt service costs, income tax expense, its subsidiaries ability to collect receivables from REPs and customers and its ability to recover its regulatory assets. For information regarding factors that may affect the future results of our consolidated operations, 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: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions) Electric $ 671 $ 654 $ 603 $ 17 $ 51 Natural Gas 564 533 492 31 41 Total Utility Operations 1,235 1,187 1,095 48 92 Corporate & Other (1) (216) (320) (87) 104 (233) Total CenterPoint Energy $ 1,019 $ 867 $ 1,008 $ 152 $ (141) (1) 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. 2024 Compared to 2023 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: • 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 $31 million for the Natural Gas reportable segment, as further discussed below; and • 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. 2023 Compared to 2022 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: • an increase in income available to common shareholders of $51 million for the Electric reportable segment, as further discussed below; • an increase in income available to common shareholders of $41 million for the Natural Gas reportable segment, as further discussed below; and • 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 57 $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. The remaining variance is due largely to an increase in borrowing costs. Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements. 58 CENTERPOINT ENERGY’S RESULTS OF OPERATIONS BY REPORTABLE SEGMENT CenterPoint Energy’s CODM views net income as the measure of profit or loss for the reportable segments. Segment results include inter-segment interest income and expense, which may result in inter-segment profit and loss. The following discussion of CenterPoint Energy’s results of operations is separated into two reportable segments, Electric and Natural Gas. Electric (CenterPoint Energy) The following table provides summary data of CenterPoint Energy’s Electric reportable segment: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues $ 4,590 $ 4,290 $ 4,108 $ 300 $ 182 Expenses: Utility natural gas, fuel and purchased power 198 176 222 (22) 46 Operation and maintenance 2,072 1,880 1,864 (192) (16) Depreciation and amortization 877 872 793 (5) (79) Taxes other than income taxes 304 272 275 (32) 3 Total expenses 3,451 3,200 3,154 (251) (46) Operating Income 1,139 1,090 954 49 136 Other Income (Expense): Interest expense and other finance charges (372) (303) (235) (69) (68) Other income, net 61 56 31 5 25 Income Before Income Taxes 828 843 750 (15) 93 Income tax expense 157 189 147 32 (42) Net Income $ 671 $ 654 $ 603 $ 17 $ 51 Throughput (in GWh): Residential 34,190 35,166 35,074 (3) % — % Total 110,831 108,766 105,541 2 % 3 % Weather (percentage of normal weather for service area): Cooling degree days 115 % 114 % 110 % 1 % 4 % Heating degree days 76 % 90 % 121 % (14) % (31) % Number of metered customers at end of period: Residential 2,640,150 2,588,510 2,534,730 2 % 2 % Total 2,971,730 2,916,028 2,858,203 2 % 2 % 59 The following table provides variance explanations by major income statement caption for the Electric reportable segment: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Customer rates and impact of the change in rate design $ 143 $ 167 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 217 122 Customer growth 26 26 Energy efficiency, offset in operation and maintenance below 5 — Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (20) (5) Pass-through revenues, offset in operation and maintenance below (5) (13) Miscellaneous revenues, including service connections and off-system sales 1 (14) Lost revenues as a result of outages associated with Hurricane Beryl (10) — Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below (70) (27) Weather, efficiency improvements and other usage impacts (9) (28) Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below 22 (46) Total $ 300 $ 182 Utility natural gas, fuel and purchased power Cost of purchased power, offset in revenues above $ (87) $ 30 Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above 65 16 Total $ (22) $ 46 Operation and maintenance Transmission costs billed by transmission providers, offset in revenues above $ (124) $ (26) Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl (112) — Contract services 16 (21) Energy efficiency, and other pass-through, offset in revenues above (1) 3 Corporate support services — (8) Labor and benefits 4 7 All other operation and maintenance expense, including materials and supplies and insurance 25 29 Total $ (192) $ (16) Depreciation and amortization Ongoing additions to plant-in-service $ (79) $ (106) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 74 27 Total $ (5) $ (79) Taxes other than income taxes Incremental capital projects placed in service, and the impact of updated property tax rates $ (26) $ 2 Franchise fees and other taxes (6) 1 Total $ (32) $ 3 Interest expense and other finance charges Changes in outstanding debt $ (63) $ (76) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (4) (4) Other, primarily AFUDC and impacts of regulatory deferrals (2) 12 Total $ (69) $ (68) Other income (expense), net Other income, including AFUDC - equity $ 5 $ 21 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above — 4 Total $ 5 $ 25 Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements. 60 Natural Gas (CenterPoint Energy) The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues $ 4,048 $ 4,279 $ 4,946 $ (231) $ (667) Expenses: Utility natural gas and fuel 1,520 1,888 2,665 368 777 Non-utility cost of revenues, including natural gas 3 3 4 — 1 Operation and maintenance 881 949 919 68 (30) Depreciation and amortization 542 513 466 (29) (47) Taxes other than income taxes 237 245 261 8 16 Total expenses 3,183 3,598 4,315 415 717 Operating Income 865 681 631 184 50 Other Income (Expense): Gain on sale — — 303 — (303) Interest expense and other finance charges (207) (188) (137) (19) (51) Other income (expense), net 14 15 (62) (1) 77 Income Before Income Taxes 672 508 735 164 (227) Income tax expense (benefit) 108 (25) 243 (133) 268 Net Income $ 564 $ 533 $ 492 $ 31 $ 41 Throughput (in Bcf): Residential 189 199 240 (5) % (17) % Commercial and industrial 426 418 424 2 % (1) % Total Throughput 615 617 664 — % (7) % Weather (percentage of 10-year average for service area): Heating degree days 78 % 86 % 106 % (8) % (20) % Number of metered customers at end of period: Residential 4,063,928 4,010,113 3,964,221 1 % 1 % Commercial and industrial 304,606 303,841 301,834 — % 1 % Total 4,368,534 4,313,954 4,266,055 1 % 1 % 61 The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Cost of natural gas, offset in utility natural gas and fuel below $ (368) $ (754) 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 1 (17) Weather and usage (11) (7) Non-volumetric and miscellaneous revenue (7) 14 Energy efficiency and other pass-through, offset in operation and maintenance below (20) 17 Non-utility revenues 15 18 Customer growth 14 20 Customer rates 145 80 Total $ (231) $ (667) Utility natural gas and fuel Cost of natural gas, offset in revenues above $ 368 $ 754 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 23 Total $ 368 $ 777 Non-utility costs of revenues, including natural gas Non-utility cost of revenues, including natural gas $ — $ 1 Total $ — $ 1 Operation and maintenance All other operations and maintenance expenses, including bad debt expense $ 23 $ (36) Energy efficiency and other pass-through, offset in revenues above 20 (17) Contract services (6) (3) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3 Labor and benefits 8 11 Corporate support services 23 12 Total $ 68 $ (30) Depreciation and amortization Ongoing additions to plant-in-service $ (29) $ (49) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 2 Total $ (29) $ (47) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (1) $ 17 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 9 (2) Total $ 8 $ 16 Gain on Sale Gain on Sale of Arkansas and Oklahoma Natural Gas businesses in 2022 $ — $ (303) Total $ — $ (303) Interest expense and other finance charges Changes in outstanding debt $ (12) $ (59) Other, primarily AFUDC and impacts of regulatory deferrals (7) 8 Total $ (19) $ (51) Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60 Other income, including AFUDC - Equity 3 10 Other (7) 7 Total $ (1) $ 77 Income Tax Expense (Benefit). For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements. 62 HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS Houston Electric’s CODM views net income as the measure of profit or loss for its reportable segment. Houston Electric consists of a single reportable segment. Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and Houston Electric’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of Houston Electric’s consolidated operations, 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: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues: TDU $ 3,862 $ 3,514 $ 3,205 $ 348 $ 309 Bond Companies 77 163 207 (86) (44) Total revenues 3,939 3,677 3,412 262 265 Expenses: Operation and maintenance, excluding Bond Companies 1,923 1,669 1,647 (254) (22) Depreciation and amortization, excluding Bond Companies 688 593 479 (95) (114) Taxes other than income taxes 295 262 261 (33) (1) Bond Companies 78 159 194 81 35 Total 2,984 2,683 2,581 (301) (102) Operating Income 955 994 831 (39) 163 Other Income (Expense): Interest expense and other finance charges (311) (259) (202) (52) (57) Interest expense on Securitization Bonds (3) (8) (13) 5 5 Other income, net 43 34 19 9 15 Income Before Income Taxes 684 761 635 (77) 126 Income tax expense 138 168 125 30 (43) Net Income $ 546 $ 593 $ 510 $ (47) $ 83 Throughput (in GWh): Residential 32,769 33,830 33,676 (3) % — % Total 106,014 103,862 100,062 2 % 4 % Weather (percentage of 10-year average for service area): Cooling degree days 115 % 114 % 110 % 1 % 4 % Heating degree days 92 % 92 % 120 % — % (28) % Number of metered customers at end of period: Residential 2,506,284 2,455,309 2,402,329 2 % 2 % Total 2,818,343 2,763,535 2,706,598 2 % 2 % 63 The following table provides variance explanations by major income statement caption for Houston Electric: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Customer rates and impact of the change in rate design $ 153 $ 187 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 217 120 Customer growth 25 25 Energy efficiency, partially offset in operation and maintenance below 5 1 Miscellaneous revenues 1 (4) Lost revenues as a result of outages associated with Hurricane Beryl (10) — Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (19) (5) Weather, efficiency improvements and other usage impacts (24) (15) Bond Companies, offset in other line items below (86) (44) Total $ 262 $ 265 Operation and maintenance, excluding Bond Companies Transmission costs billed by transmission providers, offset in revenues above $ (124) $ (26) Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl (112) — Contract services 7 (23) Energy efficiency, offset in revenues above (6) (8) Corporate support services (2) (6) Labor and benefits 1 3 All other operation and maintenance expense, including materials and supplies and insurance (18) 38 Total $ (254) $ (22) Depreciation and amortization, excluding Bond Companies Ongoing additions to plant-in-service $ (95) $ (114) Total $ (95) $ (114) 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 (26) 1 Total $ (33) $ (1) Bond Companies expense Operations and maintenance and depreciation expense, offset in revenues above $ 81 $ 35 Total $ 81 $ 35 Interest expense and other finance charges Changes in outstanding debt $ (55) $ (64) Other, primarily AFUDC and impacts of regulatory deferrals 3 7 Total $ (52) $ (57) Interest expense on Securitization Bonds Lower outstanding principal balance, offset in revenues above $ 5 $ 5 Total $ 5 $ 5 Other income, net Other income, including AFUDC - equity $ 9 $ 11 Bond Companies — 4 Total $ 9 $ 15 Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements. 64 CERC CONSOLIDATED RESULTS OF OPERATIONS CERC’s CODM views net income as the measure of profit or loss for its reportable segment. CERC consists of a single reportable segment. CERC’s results of operations are affected by seasonal fluctuations in the demand for natural gas. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates CERC charges, debt service costs and income tax expense, CERC’s ability to collect receivables from customers and CERC’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of CERC’s consolidated operations, read “Risk Factors” in Item 1A of Part I of this report. The following table provides summary data of CERC’s single reportable segment: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues $ 3,925 $ 4,149 $ 4,800 $ (224) $ (651) Expenses: Utility natural gas 1,489 1,856 2,607 367 751 Non-utility cost of revenues, including natural gas 3 3 4 — 1 Operation and maintenance 848 904 886 56 (18) Depreciation and amortization 522 493 448 (29) (45) Taxes other than income taxes 234 243 257 9 14 Total expenses 3,096 3,499 4,202 403 703 Operating Income 829 650 598 179 52 Other Income (Expense): Gain on sale — — 557 — (557) Interest expense and other finance charges (197) (178) (130) (19) (48) Other income (expense), net 12 14 (64) (2) 78 Income Before Income Taxes 644 486 961 158 (475) Income tax expense (benefit) 104 (26) 236 (130) 262 Net Income $ 540 $ 512 $ 725 $ 28 $ (213) Throughput (in BCF): Residential 184 194 233 (5) % (17) % Commercial and Industrial 390 386 389 1 % (1) % Total Throughput 574 580 622 (1) % (7) % Weather (percentage of 10-year average for service area): Heating degree days 78 % 86 % 106 % (8) % (20) % Number of metered customers at end of period: Residential 3,958,584 3,905,388 3,859,726 1 % 1 % Commercial and Industrial 293,959 293,235 291,184 — % 1 % Total 4,252,543 4,198,623 4,150,910 1 % 1 % 65 The following table provides variance explanations by major income statement caption for CERC: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (367) $ (728) 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 1 (15) Weather and usage (9) (7) Energy efficiency and other pass-through, offset in operation and maintenance below (10) 8 Non-volumetric and miscellaneous revenue (6) 13 Non-utility revenues 15 18 Customer growth 13 20 Customer rates 139 78 Total $ (224) $ (651) Utility natural gas Cost of natural gas, offset in revenues above $ 367 $ 728 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 Total $ — $ 1 Operation and maintenance All other operations and maintenance expenses, including bad debt expense $ 21 $ (36) Energy efficiency and other pass-through, offset in revenues above 10 (8) Contract services (6) — Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3 Labor and benefits 8 11 Corporate support services 23 12 Total $ 56 $ (18) Depreciation and amortization Ongoing additions to plant-in-service $ (29) $ (47) Indiana lower depreciation rates from recent rate order — — Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 2 Total $ (29) $ (45) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (1) $ 15 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 10 (2) Total $ 9 $ 14 Gain on sale Net gain on sale of Arkansas and Oklahoma Natural Gas businesses $ — $ (557) Total $ — $ (557) Interest expense and other finance charges Changes in outstanding debt $ (11) $ (56) Other, primarily AFUDC and impacts of regulatory deferrals (8) 8 Total $ (19) $ (48) Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60 Other income, including AFUDC - Equity 3 9 Other (8) 9 Total $ (2) $ 78 66 Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements. LIQUIDITY AND CAPITAL RESOURCES Cash Flows The following table summarizes the Registrants’ cash flows by category for the periods presented: Year Ended December 31, 2024 2023 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Cash provided by (used in): Operating activities $ 2,139 $ 960 $ 1,068 $ 3,877 $ 1,401 $ 2,312 $ 1,810 $ 966 $ 856 Investing activities (4,489) (2,767) (1,419) (4,233) (2,503) (1,643) (1,628) (2,435) 406 Financing activities 2,271 1,732 352 374 1,103 (668) (345) 1,324 (1,277) Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities: 2024 compared to 2023 2023 compared to 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Changes in net income after adjusting for non-cash items $ 315 $ (132) $ 153 $ 394 $ 235 $ 170 Changes in working capital (134) 195 (83) 917 229 358 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 2 — — 3 — — Other (148) (28) (46) (56) 60 20 $ (1,738) $ (441) $ (1,244) $ 2,067 $ 435 $ 1,456 (1) This change is primarily related to the receipt of proceeds at CenterPoint Energy and CERC from the issuance of customer rate relief bonds Texas by the Natural Gas Securitization Finance Corporation in 2023. For further details, see Note 7 to the consolidated financial statements. Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities: 2024 compared to 2023 2023 compared to 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Proceeds from the sale of equity securities $ — $ — $ — $ (702) $ — $ — Net change in capital expenditures (112) (363) 180 18 157 42 Net change in notes receivable from affiliated companies — 108 2 — (238) (1) Proceeds from divestitures (144) — — (1,931) — (2,075) Other — (9) 42 10 13 (15) $ (256) $ (264) $ 224 $ (2,605) $ (68) $ (2,049) 67 Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities: 2024 compared to 2023 2023 compared to 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Net changes in commercial paper outstanding $ 516 $ — $ 436 $ (981) $ — $ (227) Net changes in proceeds from issuance of Common Stock 494 — — — — — Net changes in long-term debt and term loans outstanding, excluding commercial paper 51 (6) 725 2,560 373 (778) Net changes in debt and equity issuance costs 20 5 11 (19) 4 — Net changes in short-term borrowings 6 — 6 (462) — (462) Redemption of Series A Preferred Stock 800 — — (800) — — Increased payment of Common Stock dividends (37) — — (45) — — Decreased (increased) payment of preferred stock dividends 50 — — (1) — — Payment of obligation for finance lease — — — 485 485 — Net change in notes payable from affiliated companies — 642 — — (772) 1,517 Change in contribution from parent — (41) (210) — (258) 211 Change in dividend to parent — 28 54 — (51) 348 Other (3) 1 (2) (18) (2) — $ 1,897 $ 629 $ 1,020 $ 719 $ (221) $ 609 Future Sources and Uses of Cash Material Current and Long-term Cash Requirements . The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, storm restoration costs, debt service requirements, tax payments, working capital needs and various regulatory actions. 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. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for 2025 include the following: CenterPoint Energy Houston Electric CERC (in millions) Estimated capital expenditures (1) $ 4,802 $ 2,560 $ 1,391 Estimated restoration costs associated with May 2024 Storm Events (2) 34 34 — Estimated restoration costs associated with Hurricane Beryl (2) 102 102 — Scheduled principal payments on Securitization Bonds 13 — — Expected contributions to pension plans and other postretirement plans 120 1 5 (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 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. 68 The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for 2025 through 2029. See Note 16 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2024. 2025 2026 2027 2028 2029 CenterPoint Energy (in millions) Electric $ 3,306 $ 4,358 $ 4,266 $ 4,106 $ 2,728 Natural Gas 1,465 1,604 1,469 1,344 1,327 Corporate and Other 31 20 20 20 20 Total $ 4,802 $ 5,982 $ 5,755 $ 5,470 $ 4,075 Houston Electric (1) $ 2,560 $ 3,432 $ 4,008 $ 3,904 $ 2,546 CERC (1) $ 1,391 $ 1,486 $ 1,391 $ 1,271 $ 1,254 (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, 2024: 2025 2026 2027 2028 2029 Thereafter Total (in millions) CenterPoint Energy Securitization Bonds (1) $ 13 $ 14 $ 14 $ 15 $ 16 $ 252 $ 324 Other long-term debt (1) (2) 51 2,260 1,306 2,048 919 13,738 20,322 Interest payments — Securitization Bonds (3) 16 16 15 14 13 85 159 Interest payments — other long-term debt (3) 967 937 852 771 671 7,596 11,794 Short-term borrowings 500 — — — — — 500 Commodity and other commitments (4) 805 822 664 578 555 3,059 6,483 Total cash requirements $ 2,352 $ 4,049 $ 2,851 $ 3,426 $ 2,174 $ 24,730 $ 39,582 Houston Electric Other long-term debt (1) $ — 300 $ 300 $ 500 $ — $ 7,313 $ 8,413 Interest payments — other long-term debt (3) 378 351 339 335 309 3,809 5,521 Short-term borrowings 500 — — — — — 500 Total cash requirements $ 878 $ 651 $ 639 $ 835 $ 309 $ 11,122 $ 14,434 CERC Long-term debt (1) $ 10 $ 60 $ 625 $ 1,230 $ 30 $ 3,260 $ 5,215 Interest payments — long-term debt (3) 251 250 246 188 156 1,071 2,162 Commodity and other commitments (4) 631 597 513 470 456 1,544 4,211 Total cash requirements $ 892 $ 907 $ 1,384 $ 1,888 $ 642 $ 5,875 $ 11,588 (1) Balances reflect aggregate principal amounts outstanding and do not include unamortized discounts, premiums or issuance costs. See Note 12 to the consolidated financial statements for additional information. (2) ZENS obligations are included in the 2029 column at their contingent principal amount of $9 million as of December 31, 2024. 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 ($558 million as of December 31, 2024), as discussed in Note 10 to the consolidated financial statements. (3) The Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2024. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings. (4) For a discussion of commodity and other commitments, see Note 14(a) to the consolidated financial statements. The table above does not include the following: 69 • estimated future payments for expected future AROs primarily estimated to be incurred after 2029. See Note 3(c) to the consolidated financial statements for further information. • expected contributions to pension plans and other postretirement plans in 2025. See Note 8(g) to the consolidated financial statements for further information. • operating leases. See Note 19 to the consolidated financial statements for further information. Off-Balance Sheet Arrangements Other than Houston Electric’s general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy as discussed in Note 12 and guarantees as discussed in Note 14(c) 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 For information about Hurricane Beryl, see Note 7 to the consolidated financial statements. May 2024 Storm Events For information about May 2024 Storm Events, see Note 7 to the consolidated financial statements. February 2021 Winter Storm Event For information about the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements. Indiana Electric Securitization of Generation Retirements (CenterPoint Energy) For further information about the issuance of SIGECO Securitization Bonds, see Note 7 to the consolidated financial statements. Indiana Electric CPCN (CenterPoint Energy) BTAs 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 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 70 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. PPAs 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. 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. 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. 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. 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. 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 2026. 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 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. 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. 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 71 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. Space City Solar Transmission Interconnection Project (CenterPoint Energy and Houston Electric) On December 17, 2020, Houston Electric filed a CCN with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first half of 2026. Kilgore Transmission Project (CenterPoint Energy and Houston Electric) On August 30, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Chambers County, Texas that will loop the existing 138 kV Chevron to Langston circuit number 86 on Houston Electric’s transmission system to Houston Electric’s planned Kilgore substation. On March 7, the PUCT issued a final order approving a route that was estimated to cost $60 million, including substation costs. The actual capital costs of the project, including the transmission line and the planned Kilgore substation, will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the second quarter of 2026. Mill Creek Transmission Project (CenterPoint Energy and Houston Electric) On November 17, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Harris and Montgomery Counties, Texas that will connect Houston Electric’s transmission system to Houston Electric’s planned Mill Creek substation. On November 21, 2024, the PUCT issued a final order approving a route estimated to cost $68 million. The actual capital costs of the project will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the first half of 2027. 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; 72 • 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. Admin. 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; and • 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); and • 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 73 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. Transmission and Distribution System Resiliency Plans (CenterPoint Energy and Houston Electric) House Bill 2555, codified as Tex. Util. 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. 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 for review and approval. 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. Rate Change Applications The Registrants are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Registrants are periodically involved in proceedings to adjust their capital tracking mechanisms (e.g., CSIA, DCRF, DRR, GRIP, TCOS, ECA, CECA and TDSIC), their 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). 74 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. 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. 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. 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. 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 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 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. 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. 75 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 table below reflects significant applications pending or completed since the Registrants’ combined 2023 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) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and Houston Electric (PUCT) DCRF 73 December 2023 April 2024 March 2024 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 56 March 2024 TBD TBD See discussion above under Houston Electric Rate Case . EECRF 15 May 2024 March 2025 December 2024 The requested $65 million is comprised primarily of the following: 2025 program costs of $50 million; a credit of $0.5 million related to the over-recovery of 2023 program costs; the 2023 earned bonus of $15 million; and 2025 projected evaluation, measurement and verification costs of $0.5 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. TCOS 63 November 2024 January 2025 January 2025 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) Rate Case 5 October 2023 December 2024 June 2024 See discussion above under Texas Gas Rate Case. Tax Act Rider 20 August 2024 TBD TBD 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. CERC believes its filing is consistent with the Tax Act Rider tariff approved in Docket No. OS-23-00015513. On October 1, 2024, certain parties filed comments disputing the application. Briefings were filed with an ALJ in November 2024. A hearing on the merits will be held on February 21, 2025. GRIP 71 February 2025 TBD TBD Based on net change in invested capital of $446 million. 76 Mechanism Annual Increase (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and CERC - Minnesota (MPUC) CIP Financial Incentive 8 May 2024 December 2024 November 2024 CIP Financial Incentive based on 2023 CIP program activity. Rate Case 136 November 2023 TBD TBD See discussion above under Minnesota Gas Rate Case. CenterPoint Energy and CERC - Louisiana (LPSC) RSP 12 September/October 2023 June 2024 April 2024 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. RSP 13 October 2024 TBD TBD 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) RRA 9 May 2024 September 2024 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) CSIA 4 April 2024 August 2024 July 2024 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 October 2024 February 2025 January 2025 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. 77 Mechanism Annual Increase (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and CERC - Indiana North - Gas (IURC) CSIA 9 April 2024 August 2024 July 2024 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 11 October 2024 February 2025 January 2025 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. CenterPoint Energy and CERC - Ohio - Gas (PUCO) CEP 3 March 2024 September 2024 August 2024 See discussion above under Ohio Capital Expenditure Program. DRR 12 May 2024 September 2024 August 2024 Requested an increase of $77 million to rate base for investments made in 2023, which reflects a $12 million annual increase in current revenues. A change in (over)/under-recovery variance of $0.8 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. Rate Case 100 October 2024 TBD TBD See discussion above under Ohio Gas Rate Case. CenterPoint Energy - Indiana Electric (IURC) Rate Case 80 December 2023 February 2025 February 2025 See discussion above under Indiana Electric Rate Case. TDSIC 5 February 2024 May 2024 May 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. CECA — February 2024 May 2024 June 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. ECA 6 May 2024 August 2024 August 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. TDSIC 5 August 2024 November 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. Approved rates could differ materially from proposed rates. 78 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. Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain; nevertheless, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. CenterPoint Energy will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, CenterPoint Energy does not purchase carbon credits. In connection with its net zero emissions 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 79 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 80 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...” Other Matters Credit Facilities The Registrants may draw on their respective revolving credit facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop CenterPoint Energy’s and CERC’s commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to the Registrants’ revolving credit facilities, see Note 12 to the consolidated financial statements. Based on the consolidated debt to capitalization covenant in the Registrants’ revolving credit facilities, the Registrants would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated approximately $4.0 billion as of December 31, 2024. As of February 10, 2025, the Registrants had the following revolving credit facilities and utilization of such facilities: Amount Utilized as of February 10, 2025 Registrant Size of Facility Loans Letters of Credit Commercial Paper Weighted Average Interest Rate Termination Date (in millions) CenterPoint Energy $ 2,400 $ — $ — $ 737 4.50% December 6, 2028 CenterPoint Energy (1) 250 — — — —% December 6, 2028 Houston Electric 300 — — — —% December 6, 2028 CERC 1,050 — — 497 4.51% December 6, 2028 Total $ 4,000 $ — $ — $ 1,234 (1) This credit facility was issued by SIGECO. Borrowings under each of the revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower makes representations prior to borrowing as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the revolving credit facilities, the spread to SOFR and the commitment fees fluctuate based on the borrower’s credit rating. 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. Debt Transactions For detailed information about the Registrants’ debt transactions in 2024, see Note 12 to the consolidated financial statements. Securities Registered with the SEC On May 17, 2023, the Registrants filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on May 17, 2026. For information related to the Registrants’ debt issuances in 2024, see Note 12 to the consolidated financial statements. 81 Temporary Investments As of February 10, 2025, the Registrants had no temporary investments. Money Pool The Registrants participate in a money pool through which they and certain of their subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the CenterPoint Energy money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The net funding requirements of the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of CERC’s commercial paper. The money pool may not provide sufficient funds to meet the Registrants’ cash needs. The table below summarizes CenterPoint Energy money pool activity by Registrant as of February 10, 2025: Weighted Average Interest Rate Houston Electric CERC (in millions) Money pool borrowings 4.56% $ 58 $ — Impact on Liquidity of a Downgrade in Credit Ratings The interest rate on borrowings under the Registrants’ credit facilities is based on their respective credit ratings. As of February 10, 2025, Moody’s, S&P and Fitch had assigned the following credit ratings to the borrowers: Moody’s S&P Fitch Registrant Borrower/Instrument Rating Outlook (1) Rating Outlook (2) Rating Outlook (3) CenterPoint Energy CenterPoint Energy Senior Unsecured Debt Baa2 Negative BBB Negative BBB Negative 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 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 (1) A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. (2) An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3) A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period. The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies. A decline in credit ratings could increase borrowing costs under the Registrants’ revolving credit facilities. If the Registrants’ credit ratings had been downgraded one notch by S&P and Moody’s from the ratings that existed as of December 31, 2024, the impact on the borrowing costs under the four revolving credit facilities would have been insignificant. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas reportable segments. Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, 82 CERC might need to provide cash or other collateral of as much as $159 million as of December 31, 2024. The amount of collateral will depend on seasonal variations in transportation levels. ZENS and Securities Related to ZENS (CenterPoint Energy) If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought CenterPoint Energy’s liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease 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. 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 SIGECO’s revolving credit facility, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specific types of obligations (including guarantees) exceeding $75 million by SIGECO or any of its significant subsidiaries will cause a default under SIGECO’s credit facility. A default by CenterPoint Energy would not trigger a default under its subsidiaries’ debt instruments or revolving credit facilities. Possible Acquisitions, Divestitures and Joint Ventures From time to time, the Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. The Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to the Registrants at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions. 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. 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. For further information, see Note 4 to the consolidated financial statements. Collection of Receivables from REPs (CenterPoint Energy and Houston Electric) Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, weather events, such as the February 2021 Winter Storm Event, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows. In the event of a REP’s default, Houston Electric’s tariff provides a number of remedies, 83 including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity. Other Factors that Could Affect Cash Requirements In addition to the above factors, the Registrants’ liquidity and capital resources could also be negatively affected by: • cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas reportable segment; • acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased natural gas prices, and concentration of natural gas suppliers (CenterPoint Energy and CERC); • increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC); • 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; • incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy); • 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; • the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl; • contributions to pension and postretirement benefit plans; • recovery of any losses under applicable insurance policies; • restoration costs and revenue losses resulting from future natural disasters such as hurricanes or other severe weather events and the timing of and amounts sought for recovery of such restoration costs; and • various other risks identified in “Risk Factors” in Part I, Item 1A of this report. Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money Certain provisions in certain note purchase agreements relating to debt issued by CERC have the effect of restricting the amount of secured debt issued by CERC and debt issued by subsidiaries of CERC Corp. Additionally, Houston Electric and SIGECO are limited in the amount of mortgage bonds they can issue by the General Mortgage and SIGECO’s mortgage indenture, respectively. For information about the total debt to capitalization financial covenants in the Registrants’ and SIGECO’s revolving credit facilities, see Note 12 to the consolidated financial statements. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of the Registrants’ financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on the Registrants’ financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. Our management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates 84 have been reviewed and discussed with the Audit Committee of CenterPoint Energy’s Board of Directors. For a complete discussion of the Registrants’ significant accounting policies, see Note 2 to the consolidated financial statements. Accounting for Rate Regulation Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. CenterPoint Energy, for its Electric and Natural Gas reportable segments, Houston Electric and CERC apply this accounting guidance. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability 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. If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Registrants would be required to write off or write down these regulatory assets and liabilities. For further detail on the Registrants’ regulatory assets and liabilities, see Note 7 to the consolidated financial statements. Impairment of Long-Lived Assets, Including Goodwill The Registrants review the carrying value of long-lived assets, including goodwill, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually, goodwill is tested for impairment as required by accounting guidance for goodwill. Unforeseen events, changes in market conditions, and probable regulatory disallowances, where applicable, could have a material effect on the value of long-lived assets, including goodwill, future cash flows, interest rate, and regulatory matters, and could result in an impairment charge. The Registrants recorded no impairments to long-lived assets, including goodwill during 2024, 2023 and 2022. Fair value is the amount at which an asset, liability or business could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value could be different using different estimates and assumptions in these valuation techniques. Fair value measurements require significant judgment and unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Determining the discount rates for the businesses that are not rate-regulated, such as for Energy Systems Group prior to the sale in June 2023, requires the estimation of the appropriate company-specific risk premiums for such businesses based on evaluation of industry and entity-specific risks, which includes expectations about future market or economic conditions existing on the date of the impairment test. Changes in these assumptions could have a significant impact on results of the impairment tests. Annual Goodwill Impairment Test CenterPoint Energy and CERC completed their 2024 annual goodwill impairment test during the third quarter of 2024 and determined, based on a qualitative assessment, that no goodwill impairment charge was required for any reporting unit. No qualitative factors were present that indicated impairment of CenterPoint Energy or CERC reporting units. Although no goodwill impairment resulted from the 2024 annual test, an interim goodwill impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, if CenterPoint Energy’s market capitalization falls below book value for an extended period of time, or events affecting a reporting unit such as a contemplated disposal of all or part of a reporting unit. 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, 85 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 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. The Registrants recognize a loss on abandonment when they conclude it is probable the cost will not be recovered in future rates. When the Registrants conclude it is probable that costs will be recovered in future rates, a regulatory asset is recognized. The portion of property, plant and equipment that will remain used and useful until abandonment and recovered through depreciation expense in rates will continue to be classified as property, plant and equipment until the asset is abandoned. The Registrants evaluate if an adjustment to the estimated life of the asset and, accordingly, the rate of depreciation, is required to recover the asset while it is still providing service. 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. Unbilled Revenues Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month either electronically through AMS meter communications or manual readings. At the end of each month, deliveries to non-AMS customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Information regarding deliveries to AMS customers after the last billing is obtained from actual AMS meter usage data. Unbilled electricity delivery revenue is estimated each month based on actual AMS meter data, daily supply volumes and applicable rates. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Employee Benefit Plans CenterPoint Energy sponsors pension and other retirement plans in various forms covering all employees who meet eligibility requirements. 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 86 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. 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. OTHER SIGNIFICANT MATTERS Pension Plans (CenterPoint Energy). As discussed in Note 8(b) to the consolidated financial statements, CenterPoint Energy maintains non-contributory qualified defined benefit pension plans covering eligible employees. Employer contributions for the qualified plans are based on actuarial computations that establish the minimum contribution required under ERISA and the maximum deductible contribution for income tax purposes. Under the terms of CenterPoint Energy’s pension plans, it reserves the right to change, modify or terminate the plan. CenterPoint Energy’s funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA. 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: Year Ended December 31, 2024 2023 2022 CenterPoint Energy (in millions) Minimum funding requirements for qualified pension plans $ 23 $ — $ — Employer contributions to the qualified pension plans 23 24 27 Employer contributions to the non-qualified pension plans 7 8 8 CenterPoint Energy expects to make contributions of approximately $105 million and $7 million to the qualified and non-qualified pension plans in 2025, respectively. Changes in pension obligations and plan assets may not be immediately recognized as pension expense in CenterPoint Energy’s Statements of Consolidated Income, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants. As the sponsor of a plan, CenterPoint Energy is required to (a) recognize on its Consolidated Balance Sheet an asset for the plan’s over-funded status or a liability for the plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of the fiscal year and (c) recognize changes in the funded status of the plans in the year that changes occur through adjustments to other comprehensive income and, when related to its rate-regulated utilities with recoverability of cost, to regulatory assets. The projected benefit obligation for all defined benefit pension plans was $1.5 billion as of December 31, 2024 and 2023, respectively. The impacts resulting from increases in discount rates were offset by the changes in demographic and expected versus actual returns on assets. As of December 31, 2024, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $345 million. Changes in interest rates or the market values of the securities held by the plan during 87 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. Pension cost by Registrant was as follows for the periods presented: Year Ended December 31, 2024 2023 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Pension cost $ 51 $ 23 $ 18 $ 53 $ 27 $ 19 $ 172 $ 59 $ 88 The calculation of pension cost and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. 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. 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. 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. CenterPoint Energy’s actuarially determined pension and other postemployment cost for 2024 and 2023 that is greater or less than the amounts being recovered through rates in the majority of Texas jurisdictions is deferred as a regulatory asset or liability, respectively. Pension cost for 2025, including the non-qualified benefit restoration plan, is estimated to be $49 million before applicable regulatory deferrals and capitalization, based on an expected return on plan assets of 7.00% and a discount rate of 5.60% as of December 31, 2024. If the expected return assumption were lowered by 50 basis points from 7.00% to 6.50%, the 2025 pension cost would increase by approximately $6 million. As of December 31, 2024, the pension plans projected benefit obligation, including the unfunded non-qualified pension plans, exceeded plan assets by $345 million. If the discount rate were lowered by 50 basis points from 5.60% to 5.10%, CenterPoint Energy’s projected benefit obligation would increase by approximately $60 million and its 2025 pension cost would decrease by approximately $2 million. The expected reduction in pension cost due to the decrease in discount rate is a result of the expected correlation between the reduced interest rate and appreciation of fixed income assets in pension plans with significantly more fixed income instruments than equity instruments. In addition, the assumption change would impact CenterPoint Energy’s Consolidated Balance Sheets by increasing the regulatory asset recorded as of December 31, 2024 by $54 million and would result in an incremental charge to comprehensive income in 2024 of $5 million, net of tax of $1 million, due to the increase in the projected benefit obligation. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plans will impact CenterPoint Energy’s future pension expense and liabilities. CenterPoint Energy cannot predict with certainty what these factors will be in the future.