CENTERPOINT ENERGY INC 10-K

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations No Registrant makes any representations as to the information related solely to CenterPoint Energy or the subsidiaries of CenterPoint Energy other than itself. The following combined discussion and analysis should be read in combination with the consolidated financial statements included in Item 8 herein. When discussing CenterPoint Energy’s consolidated financial information, it includes the results of Houston Electric and CERC, which, along with CenterPoint Energy, 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. OVERVIEW Background CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation and natural gas distribution facilities. For a detailed description of CenterPoint Energy’s operating subsidiaries, please read Note 1 to the consolidated financial statements. Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy that 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 that (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi and Texas, (ii) indirectly, through Indiana Gas and VEDO, 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. Reportable Segments In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our reportable segments, which are listed below. We also discuss our liquidity, capital resources and critical accounting policies. 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. 44 As of December 31, 2023, CenterPoint Energy’s reportable segments were Electric, Natural Gas, and Corporate and Other. • 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. For further information about the Electric reportable segment, see “Business — Our Business — Electric” in Item 1 of Part I of this report. • The Natural Gas reportable segment includes (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional 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. For further information about the Natural Gas reportable segment, see “Business — Our Business — Natural Gas” in Item 1 of Part I of this report. • The Corporate and Other reportable segment includes energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group, and corporate support operations that support CenterPoint Energy’s business operations. CenterPoint Energy’s Corporate and Other also includes office buildings and other real estate used for business operations. Houston Electric and CERC each consist of a single reportable segment. Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 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 carbon emission 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, 2023. See Note 11 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 capital plan, which has increased to nearly $44 billion through 2030, a nearly 10% increase from the original 10-year plan. 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 sale of our Arkansas and Oklahoma LDC businesses in 2022 and our Energy Systems Group divestiture in 2023), and issuances of equity and debt in the capital markets to satisfy these capital needs. 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 45 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 they would otherwise accept. 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 CenterPoint Energy’s, Houston Electric’s and CERC’s businesses. In accordance with applicable regulations, CenterPoint Energy, Houston Electric and CERC are making, and will continue to make, significant capital investments in their 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. CERC’s Texas and Minnesota gas jurisdictions along with Indiana Electric have filed rates cases during 2023, and Houston Electric intends to file a rate case in early 2024 and CERC’s Ohio jurisdiction intends to file a rate case in the second half of 2024. The outcome of these base rate proceedings will determine, among other things, the ability to recover certain capital investments within those jurisdictions. The outcome of these base rate proceedings is uncertain and may be impacted by the current economic environment. 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, use per customer, 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 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%. 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%. Rising inflation and sustained 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 46 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 labor shortages, resource availability, long lead times, inflation and weather. These disruptions have adversely impacted the utility industry. Like many of our peers, we have experienced disruptions to our supply chain and may continue to experience such disruptions in the future. 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, results from our energy delivery businesses may suffer. For more information, see Note 15 to the consolidated financial statements. Further, in response to concerns for protecting the environment, we have strived to take a leading stance in the transition to safer and cleaner energy by being the first combined electric and natural gas utility with regulated generation assets to adopt net zero for its Scope 1 and certain Scope 2 GHG emissions by 2035 goals. In addition, we set a Scope 3 GHG 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. Significant Events Series A Preferred Stock Redemption. On September 1, 2023, CenterPoint Energy redeemed all of the outstanding shares of Series A Preferred Stock for cash of $800 million at a redemption price of $1,000 per share, plus accumulated and unpaid dividends thereon to, but excluding, the redemption date. For further information, see Note 12 to the consolidated financial statements. Divestiture of Energy Systems Group. On May 21, 2023, Vectren Energy Services entered into an Equity Purchase Agreement to sell all of the outstanding limited liability company interests of Energy Systems Group to ESG Holdings Group, for a purchase price of $157 million, subject to customary adjustments set forth in the Equity Purchase Agreement, including adjustments based on Energy Systems Group’s net working capital at closing, indebtedness, cash and cash equivalents and transaction expenses. The transaction closed on June 30, 2023 for $154 million in cash, subject to finalization of the purchase price adjustment. For further information, see Note 4 to the consolidated financial statements. Regulatory Proceedings. On March 23, 2023, CenterPoint Energy and CERC, collectively, received approximately $1.1 billion in proceeds from the customer rate relief bonds issued by the Texas Public Financing Authority related to the February 2021 Winter Storm Event. On April 5, 2023, a final order was issued approving the $39 million revenue requirement from Houston Electric’s 2021 investment in TEEEF. On April 5, 2023, Houston Electric filed its second TEEEF filing requesting a TEEEF revenue requirement of $188 million or a net increase in TEEEF revenues of approximately $149 million . On August 28, 2023 the State Office of Administrative Hearings issued an Order setting interim rates to collect an annual revenue requirement at the filed amount. On September 26, 2023, intervenors filed testimony with various recommendations including extending the amortization period. A settlement was reached with parties that incorporated an 8 1/2 year amortization period and a TEEEF revenue requirement of $153 million based on the December 31, 2022 balance with interim rates effective December 15, 2023. The State Office of Administrative Hearings ALJ approved the revised interim rates and the settlement was approved by the PUCT in its order issued on February 1, 2024. On June 29, 2023, Indiana Electric received the net securitization proceeds of $337 million from the issuance and sale of the SIGECO Securitization Bonds to reimburse or pay for qualified costs approved by the IURC related to the completed retirement of its A.B. Brown coal-fired generation facilities. For further information, see Note 7 to the consolidated financial statements. For information related to our pending and completed regulatory proceedings to date in 2023 and to date in 2024, see “—Liquidity and Capital Resources —Regulatory Matters” below. Debt Transactions. In 2023, CenterPoint Energy issued or borrowed a combined $6.0 billion in new debt, including Houston Electric’s issuance of $1.4 billion aggregate principal amount of general mortgage bonds, CERC’s issuance of $1.5 billion aggregate principal amount of senior notes and a $500 million term loan, SIGECO Securitization Subsidiary’s issuance of $341 million aggregate principal amount of SIGECO Securitization Bonds, SIGECO’s issuance of $650 million aggregate principal amount of first mortgage bonds, and CenterPoint Energy’s issuance of $1.0 billion aggregate principal amount of convertible senior notes, $400 million aggregate principal amount of senior notes and a $250 million term loan. During 2023, CenterPoint Energy repaid or redeemed a combined $3.0 billion of debt, including CERC’s repayment of $1.0 billion of term loans and $1.332 billion of senior notes maturing in 2023, CenterPoint Energy’s repayment of its 47 $250 million term loan and $350 million of its floating rate senior notes and SIGECO’s early redemption of $91 million of first mortgage bonds, excluding scheduled principal payments on Securitization Bonds. For information about debt transactions in 2023, see Note 13 to the consolidated financial statements. CenterPoint Energy Leadership Transition. On March 15, 2023, CenterPoint Energy announced the appointment of Christopher A. Foster to the position of Executive Vice President and Chief Financial Officer, effective May 5, 2023. On September 27, 2023, CenterPoint Energy appointed Kristie L. Colvin to the position of Senior Vice President and Chief Accounting Officer of CenterPoint Energy and its affiliated subsidiaries, effective October 5, 2023. On October 26, 2023, CenterPoint Energy announced the retirement of Dave Lesar and appointment of Jason Wells to the position of President and Chief Executive Officer, effective January 5, 2024. Subsequent Events . 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. CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations. The offer and sale of Common Stock under the Equity Distribution Agreement will terminate upon the earliest of (1) the sale of all Common Stock subject to the Equity Distribution Agreement, (2) termination of the Equity Distribution Agreement, or (3) May 17, 2026. As of February 20, 2024, CenterPoint Energy has not issued any shares of Common Stock under the Equity Distribution Agreement and has not entered into any forward sale agreements. Additionally, 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 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: • CenterPoint Energy’s business strategies and strategic initiatives, restructurings, including the completed Restructuring, joint ventures and acquisitions or dispositions of assets or businesses, including the proposed sale of our Louisiana and Mississippi natural gas local distribution company businesses, and the completed sale of Energy Systems Group, 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 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 those related to Indiana Electric’s generation transition plan as part of its IRPs; • 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 requested and timely recovery of costs and a reasonable return on investment, including the timing and amount of recovery of Houston Electric’s TEEEF leases, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings; • economic conditions in regional and national markets, including changes to inflation and interest rates, and instability of banking institutions, and their effect on sales, prices and costs; • weather variations and other natural phenomena, including the impact of severe weather events on operations, capital and legislation such as in connection with the February 2021 Winter Storm Event; • volatility in the markets for natural gas as a result of, among other factors, 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 volatility in commodity prices, and tariffs and other legislation 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 carbon 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; 48 • public health threats, such as COVID-19, 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, energy deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses; • direct or indirect effects on our facilities, resources, operations 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, ice, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes and other severe weather events, pandemic health events or other occurrences; • tax legislation, including the effects 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, carbon, waste water 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 carbon 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, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; • 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 securitization for any hurricanes or other severe weather events, or natural disasters or other recovery of costs, including stranded coal-fired generation asset costs; • acquisition and merger or divestiture activities involving us or our industry, including the ability to successfully complete merger, acquisition and divestiture plans such as the proposed sale of our Louisiana and Mississippi natural gas local distribution company businesses; • 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; • 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, including energy and environmental policies under the current administration; • CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including its net zero and carbon emissions reduction goals and its operations and maintenance expenditure goals; • the outcome of litigation, including litigation related to the February 2021 Winter Storm Event; • the effect of changes in and application of accounting standards and pronouncements; and 49 • other factors discussed in “Risk Factors” in Item 1A of Part I of this report and in other reports that the Registrants file from time to time with the SEC. 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, please read “Risk Factors” in Item 1A of Part I of this report. Income available to common shareholders for the years ended December 31, 2023, 2022 and 2021 was as follows: Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions) Electric $ 654 $ 603 $ 475 $ 51 $ 128 Natural Gas 533 492 403 41 89 Total Utility Operations 1,187 1,095 878 92 217 Corporate & Other (1) (320) (87) (305) (233) 218 Discontinued Operations — — 818 — (818) Total CenterPoint Energy $ 867 $ 1,008 $ 1,391 $ (141) $ (383) (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. 2023 Compared to 2022 Net Income. 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 net income of $51 million for the Electric reportable segment, as further discussed below; • an increase in net income 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 11 to the consolidated financial statements, partially offset by $45 million of costs associated with early redemption of long-term debt in first quarter 2022. The decrease is also due to a loss on sale of $13 million and current tax expense of $32 million related to the divestiture of Energy Systems Group further discussed in Note 4 to the consolidated financial statements, as well as $19 million due to remeasurement of deferred income tax balances. The remaining variance is due largely to an increase in borrowing costs. 2022 Compared to 2021 Net Income. CenterPoint Energy reported income available to common shareholders of $1,008 million for 2022 compared to income available to common shareholders of $1,391 million for 2021. Income available to common shareholders decreased $383 million primarily due to the following items: • an increase in net income of $128 million for the Electric reportable segment, as further discussed below; • an increase in net income of $89 million for the Natural Gas reportable segment, as further discussed below; • an increase in income available to common shareholders of $218 million for Corporate and Other, primarily due to a $28 million pre-tax payment related to the impact of Board-implemented governance changes announced in July 2021, the net gain of $86 million in 2022 and a net loss of $122 million in December 2021 on the sale of Energy Transfer equity securities discussed further in Note 11 to the consolidated financial statements, partially offset by a $34 million loss in Enable Series A Preferred Unit distributions in 2021 discussed in Note 4, and a decrease in income allocated to 50 preferred shareholders of $46 million, primarily due to the conversion of the Series B Preferred Stock to Common Stock during 2021; and • a decrease in income of $818 million from discontinued operations, discussed further in Note 4 to the consolidated financial statements. Income Tax Expense. For a discussion of effective tax rate per period, see Note 14 to the consolidated financial statements. Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 51 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 The following table provides summary data of CenterPoint Energy’s Electric reportable segment: Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues $ 4,290 $ 4,108 $ 3,763 $ 182 $ 345 Expenses: Utility natural gas, fuel and purchased power 176 222 186 46 (36) Operation and maintenance 1,880 1,864 1,761 (16) (103) Depreciation and amortization 872 793 775 (79) (18) Taxes other than income taxes 272 275 268 3 (7) Total expenses 3,200 3,154 2,990 (46) (164) Operating Income 1,090 954 773 136 181 Other Income (Expense): Interest expense and other finance charges (303) (235) (226) (68) (9) Other income (expense), net 56 31 23 25 8 Income before income taxes 843 750 570 93 180 Income tax expense 189 147 95 (42) (52) Net income $ 654 $ 603 $ 475 $ 51 $ 128 Throughput (in GWh): Residential 35,166 35,074 32,067 — % 9 % Total 108,766 105,541 103,000 3 % 2 % Weather (percentage of normal weather for service area): Cooling degree days 114 % 110 % 108 % 4 % 2 % Heating degree days 90 % 121 % 82 % (31) % 39 % Number of metered customers at end of period: Residential 2,588,510 2,534,730 2,493,832 2 % 2 % Total 2,916,028 2,858,203 2,814,859 2 % 2 % 52 The following table provides variance explanations by major income statement caption for the Electric reportable segment: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Customer rates and impact of the change in rate design $ 167 $ 38 Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 122 157 Customer growth 26 28 Refund of protected and unprotected EDIT, offset in income tax expense — 32 Impacts from increased peak demand in the prior year, collected in rates in the current year — 2 Energy efficiency, partially offset in operation and maintenance below — (3) Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (5) 2 Pass-through revenues, offset in operation and maintenance below (13) 21 Miscellaneous revenues, primarily related to service connections and off-system sales (14) 11 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below (27) (33) Weather, efficiency improvements and other usage impacts (28) 54 Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below (46) 36 Total $ 182 $ 345 Utility natural gas, fuel and purchased power Cost of purchased power, offset in revenues above $ 30 $ 12 Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above 16 (48) $ 46 $ (36) Operation and maintenance Transmission costs billed by transmission providers, offset in revenues above $ (26) $ (77) Contract services (21) (2) Energy efficiency, offset in revenues above (8) 4 Support services (8) 20 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items — 3 Labor and benefits 7 7 Pass through expenses, offset in revenues above 11 (19) All other operation and maintenance expense, including materials and supplies and insurance 29 (39) Total $ (16) $ (103) Depreciation and amortization Ongoing additions to plant-in-service $ (106) $ (40) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 27 22 Total $ (79) $ (18) Taxes other than income taxes Incremental capital projects placed in service, and the impact of changes to tax rates $ 2 $ (14) Franchise fees and other taxes 1 7 Total $ 3 $ (7) Interest expense and other finance charges Changes in outstanding debt $ (76) $ (32) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (4) 8 Other, primarily AFUDC and impacts of regulatory deferrals 12 15 Total $ (68) $ (9) Other income (expense), net Other income, including AFUDC - equity $ 21 $ 8 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above 4 — Total $ 25 $ 8 Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 14 to the consolidated financial statements. 53 NATURAL GAS The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment: Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues $ 4,279 $ 4,946 $ 4,336 $ (667) $ 610 Expenses: Utility natural gas, fuel and purchased power 1,888 2,665 1,941 777 (724) Non-utility cost of revenues, including natural gas 3 4 18 1 14 Operation and maintenance 949 919 979 (30) 60 Depreciation and amortization 513 466 527 (47) 61 Taxes other than income taxes 245 261 253 16 (8) Total expenses 3,598 4,315 3,718 717 (597) Operating Income 681 631 618 50 13 Other Income (Expense) Gain on sale — 303 8 (303) 295 Interest expense and other finance charges (188) (137) (141) (51) 4 Other income (expense), net 15 (62) (2) 77 (60) Income from Continuing Operations Before Income Taxes 508 735 483 (227) 252 Income tax expense (benefit) (25) 243 80 268 (163) Net Income $ 533 $ 492 $ 403 $ 41 $ 89 Throughput (in Bcf): Residential 199 240 241 (17) % — % Commercial and industrial 418 424 428 (1) % (1) % Total Throughput 617 664 669 (7) % (1) % Weather (percentage of 10-year average for service area): Heating degree days 86 % 106 % 91 % (20) % 15 % Number of customers at end of period: Residential 4,010,113 3,964,221 4,372,428 1 % (9) % Commercial and industrial 303,841 301,834 354,602 1 % (15) % Total 4,313,954 4,266,055 4,727,030 1 % (10) % 54 The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (754) $ 923 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale (38) (457) Gross receipts tax, offset in taxes other than income taxes below (17) 19 Weather and usage (7) 22 Refund of protected and unprotected EDIT, offset in income tax expense 3 6 Non-volumetric and miscellaneous revenue 14 26 Energy efficiency and other pass-through, offset in operation and maintenance below 17 3 Non-utility revenues, including impacts of MES disposal 18 (17) Customer growth 20 16 Customer rates and impact of the change in rate design, exclusive of the TCJA impact below 77 69 Total $ (667) $ 610 Utility natural gas, fuel and purchased power Cost of natural gas, offset in revenues above $ 754 $ (923) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 23 199 $ 777 $ (724) Non-utility costs of revenues, including natural gas Non-utility cost of revenues, including natural gas $ 1 $ 14 $ 1 $ 14 Operation and maintenance Miscellaneous operations and maintenance expenses, including bad debt expense $ (36) $ (21) Energy efficiency and other pass-through, offset in revenues above (17) (3) Contract services (3) (14) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 3 125 Labor and benefits, primarily due to headcount 11 (5) Corporate support services 12 (22) Total $ (30) $ 60 Depreciation and amortization Incremental capital projects placed in service $ (49) $ (23) Lower depreciation rates in Indiana from 2021 rate order — 18 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 2 66 Total $ (47) $ 61 Taxes other than income taxes Gross receipts tax, offset in revenues above $ 17 $ (19) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 1 23 Incremental capital projects placed in service (2) (12) Total $ 16 $ (8) Gain on Sale Gain on Sale of Arkansas and Oklahoma Natural Gas businesses in 2022 $ (303) $ 295 Total $ (303) $ 295 Interest expense and other finance charges Changes in outstanding debt $ (59) $ (11) Other, primarily AFUDC and impacts of regulatory deferrals 8 15 Total $ (51) $ 4 Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 60 $ (66) AFUDC - Equity, primarily from increased capital spend 10 3 Other miscellaneous non-operating income (expenses) 7 3 Total $ 77 $ (60) Income Tax Expense (Benefit). For a discussion of effective tax rate per period by Registrant, see Note 14 to the consolidated financial statements. 55 Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 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, please read “Risk Factors” in Item 1A of Part I of this report. Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues: TDU $ 3,514 $ 3,205 $ 2,894 $ 309 $ 311 Bond Companies 163 207 240 (44) (33) Total revenues 3,677 3,412 3,134 265 278 Expenses: Operation and maintenance, excluding Bond Companies 1,669 1,647 1,591 (22) (56) Depreciation and amortization, excluding Bond Companies 593 479 429 (114) (50) Taxes other than income taxes 262 261 251 (1) (10) Bond Companies 159 194 219 35 25 Total 2,683 2,581 2,490 (102) (91) Operating Income 994 831 644 163 187 Interest expense and other finance charges (259) (202) (183) (57) (19) Interest expense on Securitization Bonds (8) (13) (21) 5 8 Other income, net 34 19 17 15 2 Income before income taxes 761 635 457 126 178 Income tax expense 168 125 76 (43) (49) Net income $ 593 $ 510 $ 381 $ 83 $ 129 Throughput (in GWh): Residential 33,830 33,676 30,650 — % 10 % Total 103,862 100,062 96,898 4 % 3 % Weather (percentage of 10-year average for service area): Cooling degree days 114 % 110 % 109 % 4 % 1 % Heating degree days 92 % 120 % 80 % (28) % 40 % Number of metered customers at end of period: Residential 2,455,309 2,402,329 2,359,168 2 % 2 % Total 2,763,535 2,706,598 2,660,938 2 % 2 % 56 The following table provides variance explanations by major income statement caption for Houston Electric: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Customer rates and impact of the change in rate design $ 187 $ 30 Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers 120 157 Customer growth 25 27 Energy efficiency, partially offset in operation and maintenance below 1 (3) Refund of protected and unprotected EDIT, offset in income tax expense — 32 Impacts from increased peak demand in the prior year, collected in rates in the current year — 2 Miscellaneous revenues (4) 5 Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (5) 1 Weather impacts and other usage (15) 60 Bond Companies, offset in other line items below (44) (33) Total $ 265 $ 278 Operation and maintenance, excluding Bond Companies Transmission costs billed by transmission providers, offset in revenues above $ (26) $ (77) Contract services (23) 3 Energy efficiency program costs, offset in revenues above (8) 3 Support services (6) 24 Labor and benefits 3 12 All other operation and maintenance expense, including materials and supplies and insurance 38 (21) Total $ (22) $ (56) Depreciation and amortization, excluding Bond Companies Ongoing additions to plant-in-service $ (114) $ (50) Total $ (114) $ (50) Taxes other than income taxes Franchise fees and other taxes $ (2) $ 4 Incremental capital projects placed in service, and the impact of changes to tax rates 1 (14) Total $ (1) $ (10) Bond Companies expense Operations and maintenance and depreciation expense, offset by revenues above $ 35 $ 25 Total $ 35 $ 25 Interest expense and other finance charges Changes in outstanding debt $ (64) $ (32) Other, primarily AFUDC and impacts of regulatory deferrals 7 13 Total $ (57) $ (19) Interest expense on Securitization Bonds Lower outstanding principal balance, offset by revenues above $ 5 $ 8 Total $ 5 $ 8 Other income, net Other income, including AFUDC - equity $ 11 $ 2 Bond Companies 4 — Total $ 15 $ 2 Income Tax Expense. For a discussion of effective tax rate per period, see Note 14 to the consolidated financial statements. 57 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, please read “Risk Factors” in Item 1A of Part I of this report. Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues: 4,149 4,800 4,200 (651) 600 Expenses: Utility natural gas 1,856 2,607 1,885 751 (722) Non-utility cost of revenues, including natural gas 3 4 17 1 13 Operation and maintenance 904 886 973 (18) 87 Depreciation and amortization 493 448 483 (45) 35 Taxes other than income taxes 243 257 249 14 (8) Total expenses 3,499 4,202 3,607 703 (595) Operating Income 650 598 593 52 5 Other Income (Expense) Gain on sale — 557 11 (557) 546 Interest expense and other finance charges (178) (130) (134) (48) 4 Other income (expense), net 14 (64) (4) 78 (60) Income Before Income Taxes 486 961 466 (475) 495 Income tax expense (benefit) (26) 236 76 262 (160) Net Income $ 512 $ 725 $ 390 $ (213) $ 335 Throughput (in BCF): Residential 194 233 235 (17) % (1) % Commercial and industrial 386 389 396 (1) % (2) % Total Throughput 580 622 631 (7) % (1) % Weather (percentage of 10-year average for service area): Heating degree days 86 % 106 % 91 % (20) % 15 % Number of customers at end of period: Residential 3,905,388 3,859,726 4,268,385 1 % (10) % Commercial and industrial 293,235 291,184 336,828 1 % (14) % Total 4,198,623 4,150,910 4,605,213 1 % (10) % 58 The following table provides variance explanations by major income statement caption for CERC: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (728) $ 921 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale (38) (457) Gross receipts tax, offset in taxes other than income taxes (15) 19 Weather and usage (7) 22 Refund of protected and unprotected EDIT, offset in income tax expense 3 6 Energy efficiency and other pass-through, offset in operation and maintenance 8 8 Non-volumetric and miscellaneous revenue 13 26 Non-utility revenues, including impacts of MES disposal 18 (17) Customer growth 20 16 Customer rates and impact of the change in rate design, exclusive of the TCJA impact 75 56 Total $ (651) $ 600 Utility natural gas Cost of natural gas, offset in revenues above $ 728 $ (921) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 23 199 Total $ 751 $ (722) Non-utility costs of revenues, including natural gas Other, primarily non-utility cost of revenues $ 1 $ 13 Total $ 1 $ 13 Operation and maintenance Miscellaneous operations and maintenance expenses, including bad debt expense $ (36) $ (20) Energy efficiency and other pass-through, offset in revenues above (8) (8) Contract services — (8) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 3 125 Labor and benefits 11 (4) Corporate Support Services 12 2 Total $ (18) $ 87 Depreciation and amortization Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale Incremental capital projects placed in service $ (47) $ (44) Indiana lower depreciation rates from recent rate order — 13 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 2 66 Total $ (45) $ 35 Taxes other than income taxes Gross receipts tax, offset in revenues $ 15 $ (19) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 1 23 Incremental capital projects placed in service (2) (12) Total 14 (8) Gain on sale Net gain on sale of Arkansas and Oklahoma Natural Gas businesses $ (557) $ 546 Total $ (557) $ 546 Interest expense and other finance charges Changes in outstanding debt $ (56) $ (11) Other, primarily AFUDC and impacts of regulatory deferrals 8 15 Total $ (48) $ 4 Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 60 $ (65) Increase in Equity AFUDC 9 2 Other miscellaneous non-operating income (expenses) 9 — Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3 Total $ 78 $ (60) 59 Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 14 to the consolidated financial statements. Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. LIQUIDITY AND CAPITAL RESOURCES Historical Cash Flows The net cash provided by (used in) operating, investing and financing activities for 2023, 2022 and 2021 is as follows: Year Ended December 31, 2023 2022 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Cash provided by (used in): Operating activities $ 3,877 $ 1,401 $ 2,312 $ 1,810 $ 966 $ 856 $ 22 $ 770 $ (1,219) Investing activities (4,233) (2,503) (1,643) (1,628) (2,435) 406 (1,851) (1,617) (1,287) Financing activities 374 1,103 (668) (345) 1,324 (1,277) 1,916 926 2,515 Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities: Year Ended December 31, 2023 compared to 2022 2022 compared to 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Changes in net income after adjusting for non-cash items $ 394 $ 235 $ 170 $ (492) $ 211 $ (169) Changes in working capital 917 229 358 (615) (177) (107) Changes in net regulatory assets and liabilities (1) 809 (89) 908 2,529 196 2,339 Changes in equity in earnings of unconsolidated affiliates (2) — — — 339 — — Changes in distributions from unconsolidated affiliates (2) — — — (155) — — Lower pension contribution 3 — — 26 — — Other (56) 60 20 156 (34) 12 $ 2,067 $ 435 $ 1,456 $ 1,788 $ 196 $ 2,075 (1) The change in net regulatory assets and liabilities at CenterPoint Energy and CERC is primarily due to securitization of the incurred natural gas costs associated with the February 2021 Winter Storm Event. See Note 7 to the consolidated financial statements for more information on the February 2021 Winter Storm Event. (2) In September 2021, CenterPoint Energy’s equity investment in Enable met the held for sale criteria and is reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income. For further information, see Note 4 to the consolidated financial statements. 60 Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities: Year Ended December 31, 2023 compared to 2022 2022 compared to 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Proceeds from the sale of equity securities $ (702) $ — $ — $ (618) $ — $ — Net change in capital expenditures 18 157 42 (1,255) (817) (337) Transaction costs related to the Enable Merger — — — 49 — — Cash received related to Enable Merger — — — (5) — — Net change in notes receivable from unconsolidated affiliates — (238) (1) — — — Proceeds from divestitures (1,931) — (2,075) 2,053 — 2,053 Other 10 13 (15) (1) (1) (23) $ (2,605) $ (68) $ (2,049) $ 223 $ (818) $ 1,693 Financing Activities. The following items contributed to (increased) decreased net cash used in financing activities: Year Ended December 31, 2023 compared to 2022 2022 compared to 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Net changes in commercial paper outstanding $ (981) $ — $ (227) $ (1,206) $ — $ (646) Net changes in long-term debt outstanding, excluding commercial paper 2,560 373 (778) (1,231) 386 (936) Net changes in debt and equity issuance costs (19) 4 — 2 (5) (4) Net changes in short-term borrowings (462) — (462) 479 — 479 Redemption of Series A Preferred Stock (800) — — — — — Increased payment of Common Stock dividends (45) — — (55) — — Decreased (increased) payment of Preferred Stock dividends (1) — — 58 — — Payment of obligation for finance lease 485 485 — (306) (306) — Net change in notes payable from affiliated companies — (772) 1,517 — (374) (2,007) Contribution from parent — (258) 211 — 1,013 149 Dividend to parent — (51) 348 — (316) (827) Other (18) (2) — (2) — — $ 719 $ (221) $ 609 $ (2,261) $ 398 $ (3,792) Future Sources and Uses of Cash The Registrants expect that anticipated 2024 cash needs will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, proceeds from sales of Common Stock under the Equity Distribution Agreement further described in Note 21 to the consolidated financial statements, anticipated cash flows from operations, and with respect to CenterPoint Energy and CERC, proceeds from commercial paper. Discretionary financing or refinancing may result in the issuance of equity securities of CenterPoint Energy or debt securities of the Registrants in the capital markets or the arrangement of additional credit facilities or term bank loans. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available on acceptable terms. Material Current and Long-term Cash Requirements . The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures are expected to be used for investment in infrastructure for electric and natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety, increase resiliency and 61 expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for 2024 include the following: CenterPoint Energy Houston Electric CERC (in millions) Estimated capital expenditures $ 3,669 $ 1,895 $ 1,385 Maturing CenterPoint Energy senior notes 850 — — Scheduled principal payments on Securitization Bonds 178 161 — Maturing SIGECO first mortgage bonds 22 — — Minimum contributions to pension plans and other post-retirement plans 17 1 4 The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for 2024 through 2028. See Note 17 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2023. 2024 2025 2026 2027 2028 CenterPoint Energy (in millions) Electric $ 2,205 $ 3,341 $ 3,589 $ 3,080 $ 3,018 Natural Gas 1,450 1,432 1,604 1,469 1,344 Corporate and Other 14 20 20 20 20 Total $ 3,669 $ 4,793 $ 5,213 $ 4,569 $ 4,382 Houston Electric (1) $ 1,895 $ 2,598 $ 2,663 $ 2,822 $ 2,816 CERC (1) $ 1,385 $ 1,370 $ 1,486 $ 1,391 $ 1,271 (1) Houston Electric and CERC each consist of a single reportable segment. Capital Expenditures for Climate-Related Projects . As part of its approximately $44.5 billion 10-year capital expenditure plan, which concludes in 2030, 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 and electric vehicle expansion. The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2023. Total 2024 2025-2026 2027-2028 2029 and thereafter (in millions) CenterPoint Energy Securitization Bonds (1) $ 502 $ 178 $ 27 $ 29 $ 268 Other long-term debt (1) (2) 18,282 872 2,311 3,894 11,205 Interest payments — Securitization Bonds (3) 187 27 32 29 99 Interest payments — other long-term debt (3) 9,238 835 1,652 1,317 5,434 Short-term borrowings 4 4 — — — Commodity and other commitments (4) 6,749 993 2,002 982 2,772 Total cash requirements $ 34,962 $ 2,909 $ 6,024 $ 6,251 $ 19,778 Houston Electric Securitization Bonds (1) $ 161 161 — — — Other long-term debt (1) 7,513 — 300 800 6,413 Interest payments — Securitization Bonds (3) 4 4 — — — Interest payments — other long-term debt (3) 5,340 306 610 583 3,841 Total cash requirements $ 13,018 $ 471 $ 910 $ 1,383 $ 10,254 62 Total 2024 2025-2026 2027-2028 2029 and thereafter (in millions) CERC Long-term debt $ 4,700 $ — $ 70 $ 1,740 $ 2,890 Interest payments — long-term debt (3) 2,213 240 478 398 1,097 Short-term borrowings 4 4 — — — Commodity and other commitments (4) 4,245 679 1,083 799 1,684 Total cash requirements $ 11,162 $ 923 $ 1,631 $ 2,937 $ 5,671 (1) Balances reflect aggregate principal amounts outstanding and do not include unamortized discounts, premiums or issuance costs. See Note 13 to the consolidated financial statements for additional information. (2) ZENS obligations are included in the 2029 and thereafter column at their contingent principal amount of $18 million as of December 31, 2023. 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 ($538 million as of December 31, 2023), as discussed in Note 11 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, 2023. 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 15(a) to the consolidated financial statements. The table above does not include the following: • estimated future payments for expected future AROs primarily estimated to be incurred after 2026. See Note 3(c) to the consolidated financial statements for further information. • expected contributions to pension plans and other postretirement plans in 2024. See Note 8(g) to the consolidated financial statements for further information. • operating leases. See Note 20 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 (see Note 13 to the consolidated financial statements) and short-term leases, the Registrants have no off-balance sheet arrangements. Regulatory Matters 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 is 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, 63 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 2025 and recovered through base rates. On July 5, 2022, Indiana Electric entered into a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price. A CPCN for the project was filed with the IURC on July 29, 2022. On September 21, 2022, an agreement in principle was reached resolving all the issues between Indiana Electric and OUCC. The Stipulation and Settlement agreement was filed on October 6, 2022 and a settlement hearing was held on November 1, 2022. On January 11, 2023, the IURC issued an order approving the settlement agreement authorizing Indiana Electric to purchase and acquire the Pike County solar project through a BTA and approved the estimated cost. The IURC also designated the project as a clean energy project under Ind. Code Ch. 8-1-8.8, approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs have exceeded the agreed upon levels in the BTA. Once pricing is updated and parties determine whether to continue with the project, Indiana Electric may have to refile for approval of the project with the IURC, which could delay the in-service date from 2025 to 2026. If Indiana Electric is not able to reach a mutually acceptable solution with the developers of the Pike County Solar project, Indiana Electric may seek to terminate 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 has approval to recover the costs of the wind facility via the CECA mechanism, which is expected to be placed in service by the end of 2026. On June 6, 2023 the IURC issued an order approving the CPCN, and thereby authorizing Indiana Electric to purchase the wind generating facility. However, as of the date 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 could be delayed from 2025 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 2021 PPA with certain modifications. On February 22, 2023 the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date could be delayed from 2024 to 2025. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved 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 could be delayed from 2025 to 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 64 estimated $334 million turbine facility is being constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana and will 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. The period to challenge FERC’s certificate in a federal district court expired on February 20, 2023. 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. Recovery of the proposed natural gas combustion turbines and regulatory asset is 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 regarding uncertainties related to our solar projects, see Item 1A of Part I 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 October 23, 2023, Indiana Electric filed rebuttal testimony with the IURC and an evidentiary hearing was held on November 2, 2023. Indiana Electric expects a decision from the IURC in the first half of 2024. Space City Solar Transmission Interconnection Project (CenterPoint Energy and Houston Electric) On December 17, 2020, Houston Electric filed a CPCN with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first quarter of 2025. 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. 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 and have been estimated to be $60 million to $99 million. A decision on the approval of the project in the PUCT proceeding is expected in the first quarter of 2024. 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. 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 and have been estimated to be $61 million to $90 million. A decision on the approval of the project in the PUCT proceeding is expected in the second or third quarter of 2024. Texas Legislation (CenterPoint Energy, Houston Electric and CERC) Houston Electric and CERC are reviewing legislation passed in 2023 and associated PUCT rulemaking projects, including the following pieces of legislation that became law during the 88th Texas Legislature, including: 65 • House Bill 1500 is effective September 1, 2023 and continues the functions of the PUCT, the Office of Public Utility Counsel, and ERCOT through 2029. This bill also includes an amendment that clarifies the use cases under which TDUs may lease and operate temporary generation during “significant” power outages; • House Bill 2263 is effective June 12, 2023 and authorizes local distribution companies to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority; • House Bill 2555 is effective June 13, 2023 and allows an electric utility to create a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, undergrounding certain lines, flood mitigation measures, and vegetation management. On January 18, 2024 the PUCT issued an Order adopting its Resiliency Plan Rule (16 TAC 25.62); • Senate Bill 947 is effective September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages; • Senate Bill 1015 is effective 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 is effective 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 is effective 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. 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 which could 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 greenhouse gas 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 January 15, 2024, reply comments are due March 15, 2024 and supplemental comments are due May 15, 2024; CERC anticipates the MPUC will hear this matter after the final comments are received. 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 a DOC investigation on anti-dumping and countervailing duties petition filed by a domestic solar manufacturer, (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 December 2, 2022, the DOC issued its preliminary determination, finding four of the eight companies being investigated are attempting to bypass U.S. duties. On August 18, 2023, the DOC announced its final determination and found that five of the eight companies investigated are attempting to bypass U.S. duties by doing minor 66 processing in one of the Southeast Asian countries before shipment to the United States. Pursuant to President Biden’s executive order issued in June 2022, duties will not be collected on any solar module and cell imports from these Southeast Asian countries until June 2024, as long as the imports are consumed in the U.S. market within six months of the termination of the executive order. The executive order could be subject to legal challenges and its effects remain uncertain. The resolution of these issues will determine what additional costs or delays our solar projects will be subject to. These impacts have resulted in cost increases for certain projects, and may result in cost increases in other projects, and such impacts have resulted in, or are expected to result in, the need for us to 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 “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 pursuant to Ind. Code ch. 8-1-39 (TDSIC Plan). Intervenors filed their case in chief on August 16, 2023 and Indiana Electric filed rebuttal on August 29, 2023. A hearing was held on September 13, 2023 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. 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, Registrants are periodically involved in proceedings to adjust its capital tracking mechanisms (e.g., CSIA, DCRF, DRR, GRIP, TCOS, ECA, CECA and TDSIC), its cost of service adjustments (e.g., RSP and RRA), its decoupling mechanism (e.g., Decoupling and SRC), and its energy efficiency cost trackers (e.g., CIP, DSMA, EECR, EECRF, EEFC and EEFR). Houston Electric Rate Case. Texas law mandates that electric utilities file a base rate proceeding no later than every four years from the date of their last base rate proceeding final order. Houston Electric’s most recent base rate proceeding order was approved by the PUCT on March 9, 2020, in Docket No. 49421. Therefore, Houston Electric is required to file its next base rate proceeding no later than March 9, 2024. 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 requested increase is approximately 3.1% or $37 million based on an historical test year ending June 30, 2023. 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 10.50% ROE on a 60.61% equity ratio. Intervenor testimony is due in early March 2024, followed by staff testimony. Rebuttal testimony is due in late March 2024 and a hearing on the merits is scheduled for mid-April 2024. A final order is expected in Q2 2024. Minnesota 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 of $69 million were implemented as of January 1, 2024. A decision on 2025 interim rates was delayed until the fourth quarter of 2024. 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 that is being made to ensure the safety and reliability of the system and normal increases in operating expenses. The rate case 67 reflects a proposed 10.4% ROE on a 55% equity ratio. A hearing is scheduled for late-April through mid-May 2024. A final order is expected in the fourth quarter of 2024. The table below reflects significant applications pending or completed since the Registrants’ combined 2022 Form 10-K was filed with the SEC through February 20, 2024. Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and Houston Electric (PUCT) DCRF (1) 86 December 2023 TBD TBD 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 for a revenue increase of $86 million, adjusted for load growth. This is the second DCRF filing made in 2023; filing two DCRFs in a year was authorized in 2023 legislative session. A request for interim rates to be implemented on February 12, 2024 was also made on December 14, 2023; the interim rate request was denied on January 9, 2024. On December 28, 2023, an intervenor requested a good cause extension, on January 5, 2024, certain parties supported it, and it was granted on January 9, 2024. On January 24, 2024, certain intervenors requested an evidentiary hearing, and the request was denied on January 25, 2024. On February 5, 2024, Houston Electric notified the ALJ that the parties have reached an agreement in principle on all issues in this proceeding, and filed an agreed expedited motion for interim rates. On February 6, 2024, the PUCT ALJ issued an order denying to abate the proceeding and retaining the procedural schedule already established. On February 7, 2024, Houston Electric on behalf of itself and all parties responded to the February 6, 2024 order to clarify that the abatement request was not intended to alter the statutory timeframe for a decision. On February 9, 2024, the PUCT ALJ issued an order setting filing deadlines and requesting briefing on interim rates. On February 13, 2024, interim rates designed to collect $220 million ($73 million incremental) were approved, to be effective April 2024. TCOS 44 August 2023 October 2023 October 2023 Based on net change in invested capital of $405 million for the period February 1, 2023 through June 30, 2023. Notice of Approval issued October 6, 2023. EECRF (1) 16 June 2023 March 2024 November 2023 The requested $53 million is comprised primarily of the following: 2024 program costs of $38 million; a credit of $2 million related to the over-recovery of 2022 program costs; the 2022 earned bonus of $16 million; and 2024 projected evaluation, measurement and verification costs of $1 million. An order approving performance bonus and rates was issued November 3, 2023. DCRF 70 April 2023 September 2023 September 2023 The net change in distribution invested capital since its last base rate proceeding of approximately $1.9 billion for the period January 1, 2019 through December 31, 2022 for a revenue increase of $85 million, adjusted for load growth. On July 14, 2023 a settlement was filed that results in a revenue increase of $70 million adjusted for load growth. Order approving the rates included in the settlement was issued September 14, 2023. TEEEF (1) 114 April 2023 December 2023 February 2024 A total Rider TEEEF revenue requirement of $188 million for cost incurred through December 31, 2022. The revenue change between the rates resulting from the 2022 TEEEF and this application is $149 million. Interim rates effective September 1, 2023. Settlement in principle announced and motion to abate filed October 12, 2023 and updated interim rates were effective December 15, 2023. The settlement incorporates an 8 1/2 year amortization period. The PUCT approved the settlement in its order that was issued February 1, 2024. TCOS 40 March 2023 May 2023 May 2023 Based on net change in invested capital of $367 million for the period August 1, 2022 through January 31, 2023. DCRF and TEEEF 117 April 2022 April 2023 April 2023 Original filing included both capital that has traditionally been recovered under DCRF and TEEEF capital; the filing was separated into traditional DCRF and TEEEF in June 2022. The traditional DCRF portion revenue requirement of $78 million was approved and was implemented September 1, 2022. A final order was issued on April 5, 2023 approving a TEEEF revenue requirement of $39 million with rates effective April 15, 2023. On April 28, 2023 and May 1, 2023 certain intervenors filed motions for rehearing of the PUCT’s April 5, 2023 order. On May 25, 2023 the PUCT issued its order on rehearing which clarified some of the findings, but did not change the approval of TEEEF cost recovery. On June 19, 2023 certain intervenors filed motions for rehearing of the May 25, 2023 order on rehearing. The PUCT denied the motions for rehearing in an order issued on August 3, 2023. See Note 7 to the consolidated financial statements for further information. CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission) GRIP 60 March 2023 June 2023 June 2023 Based on net change in invested capital for calendar year 2022 of $390 million. Rate Case (1) 37 October 2023 TBD TBD See discussion above under Texas Gas Rate Case. 68 Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and CERC - Louisiana (LPSC) RSP 6 September 2022 May 2023 April 2023 Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, net of TCJA effects considered outside of the earnings band, is $3 million based on a test year ended June 2022 and adjusted ROE of 7.05%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band, is $5 million based on a test year ended June 2022 and adjusted ROE of 4.19%. The TCJA refund impact to North Louisiana and South Louisiana was $1 million and $1 million, respectively. North Louisiana and South Louisiana also seek to recover regulatory assets due to COVID-19 bad debt expenses in the amounts of $0.7 million and $0.3 million, respectively. On April 5, 2023 the LPSC issued an order approving a joint settlement for $2.7 million in North Louisiana and $4.6 million in South Louisiana in addition to the full impacts of TCJA and COVID-19 recoveries. Implementation occurred in May 2023 upon approval of compliance tariff. RSP (1) 12 September/October 2023 TBD TBD 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. CenterPoint Energy and CERC - Minnesota (MPUC) CIP Financial Incentive 8 May 2023 September 2023 October 2023 CIP Financial Incentive based on 2022 CIP program activity. Rate Case (1) 136 November 2023 TBD TBD See discussion above under Minnesota Rate Case. CenterPoint Energy and CERC - Mississippi RRA 7 May 2023 October 2023 October 2023 Based ROE of 10.098% with 100 basis point (+/-) earnings band. Revenue increase of approximately $8 million based on 2022 test year adjusted earned ROE of 5.66%. Interim increase of approximately $1 million implemented May 31, 2023. Settled increase of approximately $7 million approved and implemented October 3, 2023. Order authorized recovery of regulatory assets due to COVID-19 in the amount of $0.3 million over the 2024 calendar year. CenterPoint Energy - Indiana South - Gas (IURC) CSIA 3 April 2023 July 2023 July 2023 Requested an increase of $33 million to rate base, which reflects approximately $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. Also included are unrecovered deferred operations and maintenance expenses of $9 million. OUCC filed on June 2, 2023, recommending approval of the proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony filed June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023. CSIA 3 October 2023 February 2024 January 2024 Requested an increase of $31 million to rate base, which reflects approximately $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. OUCC filed on December 8, 2023, recommending disallowance of two projects for customer-side replacements. Engineering rebuttal testimony was filed December 15, 2023, stating why costs were necessary for safety and integrity of customers and system. Responded to IURC docket entry requesting additional information on January 2, 2024. A hearing was held January 3, 2024. The IURC issued an order on January 31, 2024, approving the CSIA with the exception of the two projects for customer-side replacements which are not authorized for recovery. Indiana South filed revised revenue requirement schedules removing the two project costs with its compliance filing. Revised rates were effective February 1, 2024. 69 Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and CERC - Indiana North - Gas (IURC) CSIA 9 April 2023 July 2023 July 2023 Requested an increase of $95 million to rate base, which reflects approximately $9 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $5 million annually. Also included are unrecovered deferred operations and maintenance expenses of $20 million. OUCC filed on June 2, 2023, recommending approval of the proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony was filed on June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023. CSIA 9 October 2023 January 2024 January 2024 Requested an increase of $98 million to rate base, which reflects approximately $9 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. OUCC filed on December 8, 2023, recommending approval as filed. Responded to IURC Docket entry requesting additional information on January 2, 2024. A hearing was held January 3, 2024. The IURC issued an Order approving the CSIA on January 31, 2024 with rates effective January 31, 2024. CenterPoint Energy and CERC - Ohio (PUCO) DRR (1) 6 May 2023 September 2023 August 2023 Requested an increase of $46 million to rate base for investments made in 2022, which reflects a $6 million annual increase in current revenues. A change in (over)/under-recovery variance of $0.3 million annually is also included in rates. PUCO staff review and recommendation filed June 29, 2023, recommending approval as proposed. VEDO statement of issues resolved in case filed July 14, 2023. PUCO issued a Finding & Order approving the DRR August 23, 2023, and revised rates effective September 1, 2023. CenterPoint Energy - Indiana Electric (IURC) TDSIC 2 February 2023 June 2023 May 2023 Requested an increase of $31 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million). OUCC filed on April 3, 2023, recommending approval of the proposed TDSIC rates and updated plan as filed. A hearing was held on May 3, 2023. On May 30, 2023, the IURC issued an order approving the TDSIC rates and updated plan as filed with rates effective June 1, 2023. CECA — February 2023 June 2023 May 2023 Requested an increase of less than $1 million to rate base, which reflects an annual increase of less than $1 million in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million). OUCC filed on March 31, 2023, recommending approval of the proposed CECA cost recovery with a reduction of approximately $0.3 million. Rebuttal testimony was filed on April 6, 2023. A hearing was held on May 3, 2023. On May 30, 2023, the IURC issued an order approving the CECA rates with a cost recovery reduction of approximately $0.3 million with rates effective June 6, 2023. ECA (1) 1 May 2023 February 2024 February 2024 Requested an increase of $51 million to rate base, which reflects a $1 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. A hearing was held on October 24, 2023. Indiana Electric filed a proposed order on October 31, 2023. The OUCC filed a proposed order on November 8, 2023. Indiana Electric filed a response to the OUCC proposed order on November 15, 2023. A final order was issued February 7, 2024 with rates effective February 8, 2024. DSMA (1) 16 July 2023 January 2024 November 2023 The requested $45 million is comprised primarily of the following: 2024 program costs of $11 million and $26 million of lost revenue, $3 million related to the over-recovery of 2022 program costs and $11 million under-recovery related to a prior period variance adjustment; the requested $45 million is an increase of $16 million compared to the prior DSMA. A settlement between Indiana Electric and the OUCC was reached concerning the $11 million under-recovery which resolves all issues related to the DSMA for January through December 2024 including the $11 million under-recovery. The settlement provides that the IURC should approve the DSMA and that Indiana Electric will arrange for educational training on demand side management offerings. A settlement hearing was held on October 24, 2023. The IURC issued an Order approving the settlement on November 22, 2023, with rates effective January 1, 2024. 70 Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information TDSIC (1) 3 August 2023 November 2023 November 2023 Requested an increase of $27 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($0.2 million). OUCC filed on October 2, 2023 recommending approval of the proposed TDSIC rates. A hearing was held on October 31, 2023. The IURC issued an Order approving the TDSIC on November 29, 2023, with rates effective November 30, 2023. Rate Case (1) 119 December 2023 TBD TBD See discussion above under Indiana Electric Rate Case. TDSIC (1) 5 February 2024 TBD TBD Requested an increase of $36 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million). OUCC is expected to file testimony on April 2, 2024 and a hearing is scheduled for April 30, 2024. CECA (1) — February 2024 TBD TBD 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. (1) Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates. Inflation Reduction Act (IRA) On August 16, 2022, the IRA was signed into law. The new 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 IRA did not have a material impact on the Registrants’ 2023 financial results. It is likely that CenterPoint Energy and the Registrant Subsidiaries will owe CAMT in excess of their regular tax liability beginning in 2024. As a result, CenterPoint Energy and the Registrant Subsidiaries expect a temporary increase in federal cash tax payments due to this provision. Greenhouse Gas Regulation and Compliance (CenterPoint Energy) On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. On May 11, 2023, the EPA announced proposed emission limits and guidelines for carbon dioxide from fossil fuel-fired power plants under Section 111 of the Clean Air Act which, if finalized, apply new GHG performance standards for those existing coal-fired units expected to continue operation beyond December 31, 2029. We will continue to evaluate the applicability of the rule to existing and new gas-fired generating units, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029. The Biden administration recommitted the United States to the Paris Agreement, which has driven a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the U.S. commitments announced in Glasgow. In September 2021, CenterPoint Energy announced its net zero emissions goals for both Scope 1 emissions and certain Scope 2 emissions by 2035 as well as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035. 71 Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 emissions estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the U.S. Energy Information Administration (EIA) Form EIA-176 reports and do not take into account the emissions of transport customers and emissions related to upstream extraction. These emission goals are expected to be used to position CenterPoint Energy to comply with anticipated future regulatory requirements from the current and future administrations to further reduce GHG emissions. 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. The IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, and the EPA has proposed new regulations targeting reductions in methane emissions, which if implemented will 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. CenterPoint Energy’s net zero emissions goals are aligned with Indiana Electric’s generation transition plan and are expected to position Indiana Electric to comply with anticipated future regulatory requirements related to GHG emissions reductions. 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. For example, Minnesota has enacted the Natural Gas Innovation Act that seeks to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions. Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil natural gas. Additionally, cities in Minnesota within CenterPoint Energy’s Natural Gas operational footprint are considering initiatives to eliminate natural gas use in buildings and focus on electrification. Also, Minnesota cities may consider seeking legislative authority for the ability to enact voluntary enhanced energy standards for all development projects. These initiatives could have a significant impact on CenterPoint Energy and its operations, and this impact could increase if other cities and jurisdictions in its service area enact similar initiatives. 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. Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain. Although the amount of compliance costs remains uncertain, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. While the requirements of a federal or state rule remain uncertain, 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. Climate Change Trends and Uncertainties As a result of increased awareness 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 become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Registrants’ systems and services, which may result in, among other things, Indiana Electric’s generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on CenterPoint Energy’s electric generation and natural gas businesses. For example, because Indiana Electric’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Conversely, demand for the Registrants’ 72 services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, 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 emissions goals for both Scope 1 emissions and certain Scope 2 emissions by 2035. 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 756 MWs of the 700-1,000 MWs identified within Indiana Electric’s 2019/2020 IRP. 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 and electric vehicle expansion. CenterPoint Energy believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its net zero emissions goals 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. Indiana Electric plans to convert its last remaining coal unit to natural gas by 2027 and to add a significant amount of additional renewable resources through 2033. For more information regarding CenterPoint Energy’s net zero emission goals and the risks associated with them, see “Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks...” 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 and flooding, including such storms as the February 2021 Winter Storm Event. Since many of the Registrants’ facilities are located along or near the Texas gulf coast, increased or more severe hurricanes or tornadoes 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. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact our ability to secure cost-efficient insurance. 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, please see Note 13 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, 2023. 73 As of February 12, 2024, the Registrants had the following revolving credit facilities and utilization of such facilities: Amount Utilized as of February 12, 2024 Registrant Size of Facility Loans Letters of Credit Commercial Paper Weighted Average Interest Rate Termination Date (in millions) CenterPoint Energy $ 2,400 $ — $ — $ 1,272 5.51% December 6, 2027 CenterPoint Energy (1) 250 — — — —% December 6, 2027 Houston Electric 300 — — — —% December 6, 2027 CERC 1,050 — 1 359 5.49% December 6, 2027 Total $ 4,000 $ — $ 1 $ 1,631 (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 2023, see Note 13 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 2023, see Note 13 to the consolidated financial statements. Temporary Investments As of February 12, 2024, 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 12, 2024: Weighted Average Interest Rate Houston Electric CERC (in millions) Money pool investments 5.57% $ 60 $ — 74 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 12, 2024, Moody’s, S&P and Fitch had assigned the following credit ratings to senior debt of the Registrants: 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 Stable BBB Stable BBB Stable CenterPoint Energy Vectren Corp. Issuer Rating n/a n/a BBB+ Stable n/a n/a CenterPoint Energy SIGECO Senior Secured Debt A1 Stable A Stable n/a n/a Houston Electric Houston Electric Senior Secured Debt A2 Stable A Stable A Stable CERC CERC Corp. Senior Unsecured Debt A3 Stable BBB+ Stable A- Stable CERC Indiana Gas Senior Unsecured Debt n/a n/a BBB+ Stable n/a n/a (1) A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. (2) An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3) A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period. The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies. 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, 2023, the impact on the borrowing costs under the four revolving credit facilities would have been insignificant. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas reportable segments. Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC might need to provide cash or other collateral of as much as $256 million as of December 31, 2023. 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 its 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, 2023, deferred taxes of approximately $728 million would have been payable in 2023. If all the ZENS-Related Securities had been sold on December 31, 2023, capital gains taxes of approximately $81 million 75 would have been payable in 2023 based on 2023 tax rates in effect. For additional information about ZENS, see Note 11 to the consolidated financial statements. Cross Defaults Under each of CenterPoint Energy’s, Houston Electric’s and CERC’s respective revolving credit facilities and CERC’s term loan agreement, 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. The Registrants may continue to explore asset sales as a means to efficiently finance a portion of its increased capital expenditures in the future, subject to the conditions listed above. For further information, see Note 4. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. Hedging of Interest Expense for Future Debt Issuances From time to time, the Registrants may enter into interest rate agreements to hedge, in part, volatility in the U.S. treasury rates by reducing variability in cash flows related to interest payments. For further information, see Note 9(a) 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, 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, 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. 76 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 on capital and other financial markets; • various legislative or regulatory actions; • incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy and CERC); • 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 (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; • contributions to pension and postretirement benefit plans; • restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and • various other risks identified in “Risk Factors” in Item 1A of Part I 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 13 to the consolidated financial statements. CRITICAL ACCOUNTING POLICIES A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require the Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. The Registrants’ significant accounting policies are discussed in Note 2 to the consolidated financial statements. The Registrants believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of CenterPoint Energy’s Board of Directors. 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 77 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 and other intangible assets. 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 2023, 2022 and 2021. 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, 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 2023 annual goodwill impairment test during the third quarter of 2023 and determined, based on an income approach or a weighted combination of income and market approaches, that no goodwill impairment charge was required for any reporting unit. The fair values of each reporting unit significantly exceeded the carrying value of the reporting unit. Although no goodwill impairment resulted from the 2023 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 and Discontinued Operations Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell, and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale, or the disposal group, at the lower of their carrying value or their estimated fair value less cost to sell. If the disposal group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business. A disposal group that meets the held for sale criteria and also represents a strategic shift to the Registrant is also reflected as discontinued operations on the Statements of Consolidated Income, and prior periods are recast to reflect the earnings or losses from such businesses as income from discontinued operations, net of tax. 78 As described further in Note 4 to the consolidated financial statements, certain assets and liabilities of Energy Systems Group representing a business were disposed of on June 30, 2023. As a result of the held for sale criteria being met during the same period as the completion of the sale, goodwill attributable to Energy Systems Group of $134 million was reflected in the pre-tax loss on sale of $13 million based on the actual sale proceeds received at closing on June 30, 2023. 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 either a loss on abandonment or regulatory asset when they concluded it is probable the cost will be recovered in future rates. 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, 2023 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. Pension and Other Retirement 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 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 79 amount of pension and other retirement plans expense recorded. Please read “— Other Significant Matters — Pension Plans” for further discussion. NEW ACCOUNTING PRONOUNCEMENTS See Note 2(t) 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, 2023, 2022 and 2021 were as follows: Year Ended December 31, 2023 2022 2021 CenterPoint Energy (in millions) Minimum funding requirements for qualified pension plans $ — $ — $ — Employer contributions to the qualified pension plans 24 27 53 Employer contributions to the non-qualified benefit restoration plans 8 8 8 CenterPoint Energy expects to make contributions of approximately $2 million and $7 million to the qualified pension plans and non-qualified benefit restoration plans in 2024, 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 and $1.6 billion as of December 31, 2023 and 2022, respectively. This decrease was primarily due to increases in discount rates, as well as the impact of lump sum settlement payments. In December 2022, the CenterPoint Energy pension plan completed an annuity lift-out, a transaction that provided for the purchase of an irrevocable group annuity contract to fund pension plan annuities of retirees from previously divested businesses, as part of a de-risking strategy. This annuity lift-out impacted 1,119 retirees and beneficiaries, as well as reduced $138 million in pension obligations and $136 million in plan assets which were transferred to an insurance company. The transfer of plan assets is considered to be a lump sum settlement payment that reduced CenterPoint Energy pension plan’s projected benefit obligation in 2022. 80 As of December 31, 2023, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $344 million. Changes in interest rates or the market values of the securities held by the plan during a year could materially, positively or negatively, change the funded status and affect the level of pension expense and required contributions at the next remeasurement. Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. Pension cost by Registrant were as follows: Year Ended December 31, 2023 2022 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Pension cost $ 53 $ 27 $ 19 $ 172 $ 59 $ 88 $ 69 $ 34 $ 24 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, 2023, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 6.50%, which is the same as the 6.50% rate assumed as of December 31, 2022. 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, 2023, the projected benefit obligation was calculated assuming a discount rate of 4.95%, which is 0.2% lower than the 5.15% discount rate assumed as of December 31, 2022 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 2023 and 2022 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 2024, including the nonqualified benefit restoration plan, is estimated to be $51 million before applicable regulatory deferrals and capitalization, based on an expected return on plan assets of 6.50% and a discount rate of 4.95% as of December 31, 2023. If the expected return assumption were lowered by 0.50% from 6.50% to 6.00%, 2024 pension cost would increase by approximately $6 million. As of December 31, 2023, the pension plans projected benefit obligation, including the unfunded nonqualified pension plans, exceeded plan assets by $344 million. If the discount rate were lowered by 0.50% from 4.95% to 4.45%, the assumption change would increase CenterPoint Energy’s projected benefit obligation by approximately $66 million and decrease its 2024 pension cost 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, 2023 by $57 million and would result in a charge to comprehensive income in 2023 of $7 million, net of tax of $2 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. 81