EDGAR 10-K Filing

Company CIK: 48732
Filing Year: 2025
Filename: 48732_10-K_2025_0001130310-25-000040.json

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ITEM 1. BUSINESS
Item 1.Business
This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants or the subsidiaries of CenterPoint Energy, Inc. other than itself or its subsidiaries. Except as discussed in Note 12 to the consolidated financial statements, no registrant has an obligation in respect of any other registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any registrant other than the obligor in making a decision with respect to such securities.
The discussion of CenterPoint Energy’s consolidated financial information includes the financial results of Houston Electric and CERC. 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.
OUR BUSINESS
Overview
CenterPoint Energy is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution systems.
As of December 31, 2024, CenterPoint Energy’s indirect, wholly-owned subsidiaries included:
•Houston Electric, which provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas Gulf Coast area that includes the city of Houston. Bond Company IV is a wholly-owned, bankruptcy-remote entity formed solely for the purpose of purchasing and owning transition property through the issuance of Securitization Bonds;
•CERC Corp., which (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi and Texas, (ii) indirectly, through Indiana Gas and CEOH, owns and operates natural gas distribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; and
•SIGECO, which provides energy delivery services to electric and natural gas customers located in and near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.
As of December 31, 2024, CenterPoint Energy’s reportable segments were Electric, Natural Gas and Corporate and Other. Houston Electric and CERC each consist of one reportable segment. For a description of CenterPoint Energy’s reportable segments, see Note 16. For a discussion of net income by segment, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations by Reportable Segment” in Item 7 of Part II of this report.
On June 30, 2023, CenterPoint Energy completed the sale of its indirect subsidiary, Energy Systems Group, to an unaffiliated third party. On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 4 to the consolidated financial statements.
The Registrants’ principal executive offices are located at 1111 Louisiana, Houston, Texas 77002 (telephone number: 713-207-1111).
We make available free of charge on CenterPoint Energy’s Internet website, http://www.centerpointenergy.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the SEC. The SEC maintains an Internet website
that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, we make available free of charge on CenterPoint Energy’s Internet website:
•our Code of Ethics for our Chief Executive Officer and Senior Financial Officers;
•our Ethics and Compliance Code;
•our Supplier Code of Conduct;
•our Corporate Governance Guidelines; and
•the charters of the Audit, Human Capital and Compensation, Governance, Environmental and Sustainability, and Safety and Operations committees of our Board of Directors.
Any shareholder who so requests may obtain a printed copy of any of these documents from us. Changes in or waivers of our Code of Ethics for our Chief Executive Officer and Senior Financial Officers and waivers of our Ethics and Compliance Code for directors or executive officers will be posted on our Internet website within five business days of such change or waiver and maintained for at least 12 months or timely reported on Item 5.05 of Form 8-K.
Investors should also note that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may use the investor relations section of our Internet website to communicate with our investors. It is possible that the financial and other information posted there could be deemed to be material information. Except to the extent explicitly stated herein, documents and information on our Internet website are not incorporated by reference herein.
Electric (CenterPoint Energy)
The Electric reportable segment is comprised of Houston Electric and Indiana Electric.
For information regarding the properties of the Electric reportable segment, see “Properties - Electric (CenterPoint Energy and Houston Electric)” in Item 2 of this report, which information is incorporated herein by reference.
Houston Electric (CenterPoint Energy and Houston Electric)
Houston Electric is a transmission and distribution electric utility that operates wholly within the state of Texas. Houston Electric does not make direct retail or wholesale sales of electric energy or own or operate any power generating facilities other than leased TEEEF.
Electric Transmission
On behalf of REPs, Houston Electric delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kV in locations throughout Houston Electric’s certificated service territory. Houston Electric constructs and maintains transmission facilities and provides transmission services under tariffs approved by the PUCT.
Electric Distribution
Houston Electric’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer through distribution feeders. Houston Electric’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. Houston Electric provides distribution services under tariffs approved by the PUCT. PUCT rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the PUCT.
Temporary Generation.
As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event and amended in 2023, Houston Electric is leasing TEEEF that can aid in restoring power to customers during certain significant power outages that are
impacting its distribution system. On December 19, 2024, Houston Electric announced a proposal to release certain of Houston Electric’s TEEEF to the San Antonio area prior to the summer of 2025 for a period of up to two years, during which Houston Electric would not receive revenue or profit from ERCOT and would not charge Houston-area customers for these TEEEF units. As of December 31, 2024, Houston Electric leased 505 MW of TEEEF. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary - Significant Events - May 2024 Storm Events and Hurricane Beryl” in Item 7 of Part II of this report, as well as Note 7 and Note 19 to the consolidated financial statements.
Bond Companies
Houston Electric has special purpose subsidiaries consisting of the Bond Companies, which it consolidates. These consolidated special purpose subsidiaries are wholly-owned, bankruptcy-remote entities that were formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds, and conducting activities incidental thereto. The Securitization Bonds issued by Bond Company IV were repaid through charges imposed on customers in Houston Electric’s service territory. Restoration Bond Company repaid in full its last outstanding system restoration bonds at maturity on August 15, 2022, and was subsequently dissolved in 2024. On October 15, 2024, Bond Company IV repaid in full its last outstanding transition bonds at maturity. For further discussion of the Securitization Bonds issued by Bond Company IV and the outstanding balances as of December 31, 2024 and 2023, see Note 12 to the consolidated financial statements.
Customers
Houston Electric serves nearly all of the Houston/Galveston metropolitan area near the Texas Gulf Coast. Houston Electric’s customers consist of REPs, which sell electricity to metered customers in Houston Electric’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside Houston Electric’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the PUCT. Houston Electric does not have long-term contracts with any of its customers, but rather operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day. For information regarding Houston Electric’s major customers, see Note 16 to the consolidated financial statements.
The table below reflects the number of REPs and metered customers in Houston Electric’s service area as of December 31, 2024:
REPs Residential Commercial/
Industrial Total Customers
Texas Gulf Coast
67 2,506,284 312,059 2,818,343
Competition
There are no other electric transmission and distribution utilities in Houston Electric’s service area. For another provider of transmission and distribution services to provide such services in Houston Electric’s territory, it would be required to obtain a CCN from the PUCT and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. Houston Electric is not aware of any other party intending to enter this business in its service area at this time. Distributed generation (i.e., power generation located at or near the point of consumption) could result in a reduction of demand for Houston Electric’s distribution services but has not been a significant factor to date.
Seasonality
Houston Electric’s revenues are primarily derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of that REP. Houston Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months when more electricity is used for cooling purposes.
Franchises
Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to
conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 40 years.
Indiana Electric (CenterPoint Energy)
Indiana Electric consists of SIGECO’s electric transmission and distribution services, including its electric generation assets and wholesale power operations. The table below reflects the number of metered customers to whom Indiana Electric supplied electric service as of December 31, 2024:
Residential Commercial/Industrial Total Customers
Southwestern Indiana 133,866 19,541 153,407
System Load
Total load and the related reserve margin at the time of the system summer peak on August 29, 2024, is presented below in MW, except for reserve margin at peak:
Total load at peak 1,062
Generating capability 720
Purchase supply (effective capacity) (1) 698
Interruptible contracts & direct load control 15
Total power supply capacity 1,433
Reserve margin at peak 35 %
(1)Indiana Electric procured bi-lateral capacity contracts starting in the 2023-2024 MISO planning year. These contracts were procured before MISO moved to a seasonal construct, which allowed several generating units to receive accreditation in the summer season that would not have received any accreditation under MISO's previous annual construct. This resulted in a reserve margin that is higher than normal in the summer, but was limited to the summer season.
The winter peak load for the 2023-2024 season of approximately 835 MW occurred on January 16, 2024.
Solar and Wind
Indiana Electric has entered into various PPAs to purchase solar power and wind power to meet its future generation needs as reported in the table below:
Power Type Counterparty Location Expected Date in Service Capacity
(MW) Term
(in Years)
Solar Clenera, LLC Warrick County, Indiana 2026 100 25
Solar Oriden Vermillion County, Indiana 2026 185 15
Solar Origis Knox County, Indiana 2026 150 20
Wind NextEra Energy, Inc. Knox County, Illinois 2026 147 25
For further information about Indiana Electric’s solar power and wind power activities, see “Item 2. Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
Coal Purchases
Coal for coal-fired generating stations has been supplied from operators of nearby coal mines as there are substantial coal reserves in the southern Indiana area. Major suppliers are those that account for greater than 10% of Indiana Electric’s coal purchases. For the year ended December 31, 2024, Sunrise LLC accounted for 88% of Indiana Electric’s coal purchases, with the remaining 12% being purchased from other suppliers.
The table below presents information related to coal purchases during the year ended December 31, 2024 and coal inventory as of December 31, 2024:
(In tons, except average cost per ton)
Coal purchased for generating electricity 883,308
Coal inventory as of December 31, 2024
263,321
Average cost of coal per ton $54.41
Firm Purchase Supply
Indiana Electric enters into long-term purchase supply agreements to meet its generation needs as disclosed below:
Fuel Type Provider Location Contract Expiration Capacity
(MW) Purchased in 2024
(in GWh)
Coal OVEC (1) Indiana and Ohio 2040 32 178
Wind Benton County Wind Farm, LLC Benton County, Indiana 2028 30 83
Wind Fowler Ridge II Wind Farm, LLC Benton/Tippecanoe Counties, Indiana 2029 50 134
112 395
(1)As part of its power portfolio, Indiana Electric is a 1.5% shareholder in the OVEC. Based on its participation in the ICPA between OVEC and its shareholder companies, Indiana Electric has the right to 1.5% of OVEC’s generating capacity output and shares in 1.5% of the operating expenses and debt obligations of OVEC.
MISO-Related Activity
Indiana Electric is a member of the MISO, a FERC-approved regional transmission organization. The MISO serves the electric transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission facilities and generation facilities as well as other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position.
MISO-related activity for the year ended December 31, 2024 was as follows:
In GWh
Net purchases (1) 2,406
Net sales (2) -
(1)Represents intervals when purchases from the MISO were in excess of generation sold to the MISO.
(2)Represents intervals when sales to the MISO were in excess of purchases from the MISO. Net sales were insignificant during 2024 primarily due to the retirement of SIGECO’s A.B. Brown coal generating facilities in 2023 and SIGECO’s exit from joint operations in the Warrick 4 coal generating facility on January 1, 2024.
Interconnections
As of December 31, 2024, Indiana Electric had interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc. and Big Rivers Electric Corporation providing the ability to simultaneously interchange approximately 645 MW during peak load periods. Indiana Electric, as required as a member of the MISO, has turned over operational control of the interchange facilities
and its own transmission assets to the MISO. Indiana Electric, in conjunction with the MISO, must operate the bulk electric transmission system in accordance with NERC Reliability Standards. As a result, interchange capability varies based on regional transmission system configuration, generation dispatch, seasonal facility ratings and other factors. Indiana Electric is in compliance with reliability standards promulgated by NERC.
SIGECO Securitization Subsidiary
SIGECO has a special purpose subsidiary, SIGECO Securitization Subsidiary, which it consolidates. This consolidated special purpose subsidiary is a wholly-owned, bankruptcy-remote entity that was formed solely for the purpose of facilitating the securitization financing of qualified costs. The obligations of the SIGECO Securitization Bonds are repaid through charges imposed on customers in Indiana Electric’s service territory. For further discussion of the SIGECO Securitization Bonds and the outstanding balance as of December 31, 2024, see Note 12 to the consolidated financial statements.
Competition
There are no other electric transmission and distribution utilities in Indiana Electric’s service area. Indiana Electric is a vertically integrated utility that owns the generation, transmission, and distribution components of a utility.
For another provider of transmission and distribution services to provide such services in Indiana Electric’s territory, it would be required to obtain IURC approval of such service territory. Indiana service territory certificates are exclusive. Distributed generation (i.e., power generation located at or near the point of consumption) could result in reduced demand for Indiana Electric’s distribution services but has not been a significant factor to date.
Seasonality
Indiana Electric’s revenues are primarily derived from rates that it collects from customers in its service territory based on the amount of electricity it delivers. Indiana Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months when more electricity is used for cooling purposes, and during the cooler months when more electricity is used for heating purposes.
Natural Gas (CenterPoint Energy and CERC)
CenterPoint Energy’s and CERC’s Natural Gas engage in regulated intrastate natural gas sales to, and natural gas transportation and storage for, residential, commercial, industrial and transportation customers. CenterPoint Energy’s and CERC’s Natural Gas provide permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP. CenterPoint Energy’s and CERC’s Natural Gas also provided services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales and home repair protection plans to natural gas customers in Indiana, Mississippi, Ohio and Texas through a third party as of December 31, 2024.
For information regarding the properties of the Natural Gas reportable segment, read “Properties - Natural Gas (CenterPoint Energy and CERC)” in Item 2 of this report, which information is incorporated herein by reference.
On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction was approved by final orders issued by the MPSC on December 3, 2024 and by the LPSC on December 17, 2024. The transaction is expected to close in the first quarter of 2025. For further information, see Note 4 to the consolidated financial statements.
Customers
The table below reflects the number of CenterPoint Energy’s and CERC’s Natural Gas customers by state as of December 31, 2024:
Residential Commercial/
Industrial/Transportation Total Customers
Indiana (Indiana Gas) 606,536 55,745 662,281
Louisiana 231,962 16,214 248,176
Minnesota 859,065 72,890 931,955
Mississippi 123,175 13,152 136,327
Ohio 310,541 24,589 335,130
Texas 1,827,305 111,369 1,938,674
Total CERC Natural Gas 3,958,584 293,959 4,252,543
Indiana (SIGECO) 105,344 10,647 115,991
Total CenterPoint Energy Natural Gas 4,063,928 304,606 4,368,534
The largest metropolitan areas served in each state were Houston, Texas; Minneapolis, Minnesota; Shreveport, Louisiana; Biloxi, Mississippi; Evansville, Indiana; and Dayton, Ohio.
The table below reflects the percentage of total throughput by customer type for the year ended December 31, 2024:
CenterPoint Energy CERC
Residential 31 % 32 %
Commercial/Industrial and Transportation 69 % 68 %
Total Throughput 100 % 100 %
Seasonality
The demand for natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal and affected by variations in weather conditions. In 2024, approximately 64% and 65% of CenterPoint Energy’s and CERC’s Natural Gas total throughput occurred in the first and fourth quarters, respectively. These patterns reflect the higher demand for natural gas for heating purposes during the colder months.
Supply and Transportation
In 2024, CenterPoint Energy’s Natural Gas purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to three years. Major suppliers are those that account for greater than 10% of CenterPoint Energy’s or CERC’s annual natural gas supply purchases.
Major suppliers of natural gas for the year ended December 31, 2024 were as follows:
CenterPoint Energy CERC
Tenaska Marketing Ventures, LLC 33 % 31 %
BP Energy Company
11 % 12 %
Macquarie Energy, LLC
11 % 11 %
Total of major suppliers 55 % 54 %
Numerous other suppliers provided the remainder of CenterPoint Energy’s and CERC’s natural gas supply requirements.
CenterPoint Energy’s and CERC’s Natural Gas transports their natural gas supplies through various intrastate and interstate pipelines under contracts with remaining terms, including extensions, varying from one to fifteen years. CenterPoint Energy’s and CERC’s Natural Gas anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.
CenterPoint Energy’s and CERC’s Natural Gas actively engage in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless collars and caps) with CenterPoint Energy’s and CERC’s Natural Gas’ physical gas suppliers. Their gas supply plans generally call for 50-75% of normal winter supplies to be stabilized in some fashion.
The regulations of the states in which CenterPoint Energy’s and CERC’s Natural Gas operate allow them to pass through changes in the cost of natural gas, including savings and costs of financial derivatives associated with the index-priced physical supply, to their customers under purchased gas adjustment provisions in their tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies.
CenterPoint Energy’s and CERC’s Natural Gas use various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. CenterPoint Energy’s and CERC’s Natural Gas may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.
On an ongoing basis, CenterPoint Energy’s and CERC’s Natural Gas enter into contracts to provide sufficient supplies and pipeline capacity to meet their customer requirements. However, it is possible for limited service disruptions to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors.
CenterPoint Energy’s and CERC’s Natural Gas businesses continue to utilize AMAs associated with their utility distribution service in Indiana, Louisiana, Minnesota, Mississippi and Texas. Generally, AMAs are contracts between CenterPoint Energy’s and CERC’s Natural Gas and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, CenterPoint Energy’s and CERC’s Natural Gas agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for CenterPoint Energy’s and CERC’s Natural Gas and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s Natural Gas. CenterPoint Energy’s and CERC’s Natural Gas may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s Natural Gas has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs. The AMAs have varying terms, the longest of which expires in 2029. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s Natural Gas either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. For amounts outstanding under these AMAs, see Note 12 to the consolidated financial statements.
Competition
CenterPoint Energy’s and CERC’s Natural Gas compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CenterPoint Energy’s and CERC’s Natural Gas’ facilities and market, sell and/or transport natural gas directly to commercial and industrial customers.
Corporate and Other (CenterPoint Energy)
CenterPoint Energy’s Corporate and Other consists of corporate support operations that support CenterPoint Energy’s business operations and also includes office buildings and other real estate used for business operations. CenterPoint Energy’s Corporate and Other also consisted of energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group. For additional information on the sale of Energy Systems Group, see Note 4 to the consolidated financial statements.
REGULATION
The Registrants are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. The following discussion is based on regulation in the Registrants’ businesses as of December 31, 2024.
Federal Energy Regulatory Commission
FERC has jurisdiction under the NGA and the NGPA, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. FERC also regulates the transmission and wholesale sales of electricity in interstate commerce, mergers, acquisitions and corporate transactions by electricity companies, energy markets, reliability standards and the issuance of short-term debt by public utilities regulated by FERC. FERC has authority to prohibit market manipulation in connection with FERC-regulated transactions, to conduct audits and investigations, and to impose significant civil penalties (up to approximately $1.6 million per day per violation, subject to periodic adjustment to account for inflation) for statutory violations and violations of the FERC’s rules or orders.
Indiana Electric is a “public utility” under the FPA and is subject to regulation by FERC. Houston Electric is not a “public utility” under the FPA and, therefore, is not generally regulated by FERC, although certain of its transactions are subject to limited FERC jurisdiction. FERC has certain responsibilities with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT. FERC has designated NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The ERO and FERC have authority to (a) impose fines and other sanctions on applicable entities that fail to comply with approved standards and (b) audit compliance with approved standards. FERC has approved the delegation by NERC of authority for reliability in ERCOT to the Texas RE and in MISO to ReliabilityFirst Corporation. Neither Houston Electric nor Indiana Electric anticipate that the reliability standards proposed by NERC and approved by FERC will have a material adverse impact on their operations. To the extent that Houston Electric and Indiana Electric are required to make additional expenditures to comply with these standards, it is anticipated that Houston Electric and Indiana Electric will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT and the MISO, respectively, for electric transmission provided.
As a public utility holding company, under the Public Utility Holding Company Act of 2005, CenterPoint Energy and its consolidated subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by FERC and state regulatory authorities in certain circumstances.
For a discussion of the Registrants’ ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
State and Local Regulation - Electric Transmission & Distribution (CenterPoint Energy and Houston Electric)
Houston Electric is a member of ERCOT, which serves as the independent system operator and regional reliability coordinator for member electric power systems in most of Texas. The ERCOT market represents approximately 90% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market operates under the reliability standards developed by NERC, approved by FERC and monitored and enforced by the Texas RE. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid.
The ERCOT ISO is responsible for operating the bulk electric power supply system in the ERCOT market. Houston Electric’s transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. Houston Electric participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.
Houston Electric conducts its operations pursuant to a CCN issued by the PUCT that covers its present service area and facilities. The PUCT and certain municipalities have the authority to set the rates and terms of service provided by Houston Electric under cost-of-service rate regulation. Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 40 years.
In ERCOT, end users purchase their electricity directly from certificated REPs. Houston Electric’s distribution rates charged to REPs for residential and small commercial customers are primarily based on amounts of energy delivered, whereas
distribution rates for a majority of large commercial and industrial customers are primarily based on peak demand. All REPs in Houston Electric’s service area pay the same rates and other charges for transmission and distribution services. This regulated delivery charge may include the transmission and distribution rate (which includes municipal franchise fees), a DCRF mechanism for recovery of incremental distribution-invested capital above that which is already reflected in the base distribution rate, a TEEEF mechanism for recovery of costs associated with leasing and operating TEEEF, a TCRF mechanism for recovery of approved wholesale transmission cost changes billed by a transmission service provider, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an EECRF charge, and charges associated with securitization of regulatory assets, stranded costs and restoration costs. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay Houston Electric the same rates and other charges for transmission services.
With the IURC’s approval, Indiana Electric is a member of the MISO, a FERC-approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission and generation facilities as well as those of other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing as determined by the MISO market. Indiana Electric also receives transmission revenue that results from other members’ use of Indiana Electric’s transmission system. Generally, these transmission revenues, along with costs charged by the MISO, are considered components of base rates and any variance from that included in base rates is recovered from or refunded to retail customers through tracking mechanisms.
For a discussion of certain of Houston Electric’s and Indiana Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
State and Local Regulation - Electric Generation (CenterPoint Energy)
The energy and capacity secured from Indiana Electric’s available generation resources are utilized primarily to serve the needs of retail electric customers residing within Indiana Electric’s franchised service territory. Costs of operating Indiana Electric’s generation facilities are recovered through IURC-approved base rates as well as periodic rate recovery mechanisms including the CECA, ECA, FAC, MCRA, and RCRA mechanism. Costs that are deemed unreasonable or imprudent by the IURC may not be recoverable through retail electric rates. Indiana Electric also receives revenues from the MISO to compensate it for benefits the generation facilities provide to the transmission system. Proceeds from the sales of energy from Indiana Electric’s generation facilities that exceed the requirements of retail customers are shared by Indiana Electric and retail electric customers.
The generation facilities owned and operated by Indiana Electric are subject to various environmental regulations enforced by the EPA and the IDEM. Operations of Indiana Electric’s generation facilities are subject to regulation by the EPA and the IDEM as it pertains to the discharge of constituents from the generation facilities. For further discussion, see “Our Business - Environmental Matters” below.
For a discussion of Indiana Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
State and Local Regulation - Natural Gas (CenterPoint Energy and CERC)
In almost all communities in which CenterPoint Energy’s and CERC’s Natural Gas provides natural gas distribution services, they operate under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 20 to 30 years. CenterPoint Energy’s and CERC’s Natural Gas expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.
Substantially all of CenterPoint Energy’s and CERC’s Natural Gas is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by those municipalities that have retained original jurisdiction. In certain of the jurisdictions in which they operate, CenterPoint Energy’s and CERC’s Natural Gas have annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.
For a discussion of certain of CenterPoint Energy’s and CERC’s Natural Gas’ ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
Department of Transportation (CenterPoint Energy and CERC)
CenterPoint Energy and CERC are subject to regulation by PHMSA under the NGPSA and the HLPSA. The NGPSA delegated to PHMSA through DOT the authority to regulate gas pipelines. The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Every four years PHMSA is up for reauthorization by Congress and with that reauthorization comes changes to the legislative requirements that Congress sets forth for the oversight of natural gas and hazardous liquid pipelines. In 2020, the PIPES Act was enacted. The PIPES Act reauthorized PHMSA through 2023 and imposed a few new mandates on the agency. The law establishes a PHMSA technology pilot, authorizes a new idled pipe operating status and contains process protections for operators during PHMSA enforcement proceedings. Section 114 of the PIPES Act is a self-mandating rule for natural gas pipeline operations like CERC’s that focuses on processes and procedures to eliminate or reduce emissions during normal operations. Further, Section 113 of the PIPES Act directed PHMSA to develop regulations to require natural gas pipeline operators to implement leak detection and repair programs, as well as requirements for mitigating emissions in operations. The PIPES Act of 2023 was approved by the House Transportation and Infrastructure Committee on December 6, 2023 to reauthorize PHMSA’s safety programs for the next four years. Final versions of the Section 113 Leak Detection and Repair, and Safety of Natural Gas Distribution Pipelines, 2020 PIPES Act rules remain frozen until a Department of Transportation appointee can review and proceed further.
In January 2021, PHMSA published a final rule amending the federal Pipeline Safety Regulations to ease regulatory burdens on the construction, operation, and maintenance of gas transmission, distribution, and gathering systems.
CenterPoint Energy and CERC anticipate that compliance with PHMSA’s regulations, performance of the remediation activities by CenterPoint Energy’s and CERC’s Natural Gas and intrastate pipelines, and verification of records on maximum allowable operating pressure will continue to require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. In particular, the cost of compliance with the DOT’s integrity management rules will depend on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas, may also affect the costs incurred. Implementation by PHMSA of the PIPES Act, in particular the final rule implementing Section 113, acts reauthorizing PHMSA or other future acts may result in other regulations or the reinterpretation of existing regulations that could impact compliance costs. In addition, CenterPoint Energy and CERC may be subject to the DOT’s enforcement actions and penalties if they fail to comply with pipeline regulations.
ENVIRONMENTAL MATTERS
The following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2024. The Registrants’ operations are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric transmission and distribution systems, steam electric and renewable generation systems and the facilities that support these systems, the Registrants must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact the Registrants’ business activities in many ways, including, but not limited to:
•restricting the way the Registrants can handle or dispose of wastes, including wastewater discharges and air emissions;
•limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species;
•requiring remedial action and monitoring to mitigate environmental conditions caused by the Registrants’ operations or attributable to former operations;
•enjoining the operations of facilities with permits issued pursuant to such environmental laws and regulations; and
•impacting the demand for the Registrants’ services by directly or indirectly affecting the use or price of fossil fuels, including, but not limited to, natural gas.
To comply with these requirements, the Registrants may need to spend substantial amounts and devote other resources from time to time to, among other activities:
•construct or acquire new facilities and equipment;
•acquire permits for facility operations or purchase emissions allowances;
•modify, upgrade or replace existing and proposed equipment; and
•decommission or remediate waste management areas, fuel storage facilities and other locations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, revocation of permits, the imposition of remedial actions and monitoring and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to assess, clean up and restore sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and/or property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
Increasingly, environmental regulation has resulted in more restrictions and limitations on activities that may impact the environment. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and monitoring, and actual future expenditures may be different from the amounts currently anticipated. The Registrants try to anticipate future regulatory requirements that might be imposed and plan accordingly to maintain compliance with changing environmental laws and regulations.
Based on current regulatory requirements and interpretations, the Registrants do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on their business, financial position, results of operations or cash flows. In addition, the Registrants believe that their current environmental remediation activities will not materially interrupt or diminish their operational ability. The Registrants cannot provide assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause them to incur significant costs. The following is a discussion of material current environmental and safety issues, laws and regulations that relate to the Registrants’ operations. The Registrants believe that they are in substantial compliance with these environmental laws and regulations.
Greenhouse Gas and Climate Change-Related Regulation and Compliance (CenterPoint Energy)
There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG on the state, federal, or international level. The EPA released its initial GHG regulation for fossil fuel-fired electric generating units in 2015. Since then, various iterations of GHG regulations have been promulgated, withdrawn and litigated, and the current rule applicable to fossil fuel-fired electric generating units was finalized in April 2024. In April 2024, the EPA finalized the current New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, Reconstructed Fossil Fuel-Fired Units; and Repeal of the Affordable Clean Energy Rule, which applies new GHG performance standards for those existing coal-fired power plants expected to continue operation beyond December 31, 2029. The rule is currently being challenged by a variety of stakeholders in litigation before the Circuit Court of Appeals for the D.C. Circuit. In October 2024, the U.S. Supreme Court declined to stay the implementation of the rule while the rule is on judicial review. On February 19, 2021, the United States formally rejoined the Paris Agreement, which drove a renewed regulatory push to require further GHG emission reductions from the energy sector, and led negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, the United States announced goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035 from a 2021 baseline, which formed the basis of the U.S. commitments announced in Glasgow. Nevertheless, on January 20, 2025, President Trump signed an executive order to withdraw the United States from the Paris Agreement, marking a significant shift in U.S. climate policy. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. Additionally, in January 2025, President Trump signed a series of executive orders that, among other things, (i) call upon the EPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act and issue guidance on the “social cost of carbon” to consider whether such metric should be eliminated, (ii) direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, (iii) temporarily halt certain federal government agencies from issuing approvals, permits and loans for onshore wind projects pending the completion of certain assessments and reviews and (iv) pause the disbursement of funds appropriated through the IRA and the Infrastructure Investments and Jobs Act.
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 from a 2021 baseline. Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 emissions 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 any future administrations to further reduce GHG emissions. For more information regarding CenterPoint Energy’s net zero and GHG emissions reduction goals and their related risks, see “Risk Factors - Risk Factors Affecting Regulatory, Environmental and Legal Risks - CenterPoint Energy is subject to operational and financial risks ...” 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, the rules for which were finalized on November 18, 2024, and the EPA published final, new regulations targeting reductions in methane emissions on March 8, 2024, which may increase costs related to production, transmission and storage of natural gas.
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. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than through TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within their respective service territories. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services. 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 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 relative to other fossil fuels 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.
On March 6, 2024, the SEC adopted final rules that require the Registrants to disclose certain climate-related information in registration statements and annual reports. Litigation challenging the new rule was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC announced that it is voluntarily delaying the implementation of the climate disclosure regulations while the U.S. Court of Appeals considers the litigation. While a majority of the reporting requirements would have been applicable to the Registrants in the fiscal year beginning in 2025, with the addition of assurance reporting for GHG inventories starting in 2029 for large accelerated filers, as of April 12, 2024, the effective date of the final rules has been delayed indefinitely and the SEC has indicated that it will publish a document in the Federal Register at the conclusion of the stay addressing a new effective date for the final rules. On February 11, 2025, the SEC notified the U.S. Court of Appeals of a statement issued by the SEC’s Acting Chairman regarding, among other things, the fact that the majority of current SEC Commissioners had previously voted against adopting the rules, and requested that the U.S. Court of Appeals not schedule the case for argument to provide time for the SEC to deliberate and determine the appropriate next steps in the cases. The Registrants continue to evaluate the impact of the final rules on their respective consolidated financial statements and related disclosures.
Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain. 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 and GHG emissions goals, CenterPoint Energy expects to purchase carbon credits in the future; however, CenterPoint Energy does not currently expect the number of credits, or cost for those credits, to be material.
For further information on climate change trends and uncertainties, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters - Climate Change Trends and Uncertainties” in Item 7 of Part II of this report.
Air Emissions
The Registrants’ operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating facilities and natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions. The Registrants may be required to obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. The Registrants may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.
Water Discharges
The Registrants’ operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material into wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from the Registrants’ pipelines or facilities could result in fines or penalties as well as significant remedial obligations.
Waters of the United States
In April 2020 the EPA proposed a new set of rules that sought to clarify the Clean Water Act’s jurisdiction over “waters of the United States,” but that set of rules was later vacated by decisions in the U.S. federal district courts in New Mexico and Arizona. On December 30, 2022, the EPA and the U.S. Army Corps of Engineers announced the final “Revised Definition of ‘waters of the United States”’ rule, which was published on January 18, 2023 and became effective on March 20, 2023. However, on May 25, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands in the case of Sackett v. Environmental Protection Agency, and on August 29, 2023, the EPA issued a final rule that seeks to conform with the U.S. Supreme Court decision. As a result of ongoing rulemaking litigation, the Registrants’ operations in all states with the exception of Minnesota fall under the pre-2015 regulatory regime consistent with the Supreme Court decision in Sackett, while operations in Minnesota fall under the 2023 rule, as amended. CenterPoint Energy is unable to predict the outcome of current or future litigation or regulatory proceedings, but does not expect a material impact on its operations relating to these rules. CenterPoint Energy will continue to monitor regulatory and legal developments relating to the Clean Water Act that may affect its business.
ELG
In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards, which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. In February 2019, the IURC approved Indiana Electric’s ELG Compliance Plan for its F.B. Culley Generating Station, which was completed in compliance with the requirements of ELG. On April 25, 2024, the EPA released its final Supplemental ELG and Standards for the Steam Electric Generating Point Source Category. The Registrants currently anticipate that they will be in compliance with the Supplemental ELG Guidelines at the Culley facility due to previous wastewater treatment upgrades.
Cooling Water Intake Structures
Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014, the EPA finalized a regulation requiring installation of “best technology available” to mitigate impingement and entrainment of aquatic species in cooling water intake structures. Indiana Electric is currently completing the required ecological studies and anticipates timely compliance at its F.B. Culley facility in 2025.
Hazardous Waste
The Registrants’ operations generate wastes, including some hazardous wastes, that are subject to the federal RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment, transport and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous wastewaters produced and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements.
Coal Ash
Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. In 2015, the EPA finalized its CCR Rule, which regulates coal ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s remaining generating units will continue to be beneficially reused. Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies were necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. Groundwater monitoring indicates potential groundwater impacts adjacent to Indiana Electric’s ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. Indiana Electric completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond failed the aquifer placement location restriction. As a result of this failure, Indiana Electric was required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021. Indiana Electric filed timely requests for extensions available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through October 15, 2023. On January 22, 2021, Indiana Electric received letters from the EPA for both the F.B. Culley and A.B. Brown facilities that determined Indiana Electric’s extension submittals complete and extended the compliance deadline of April 11, 2021 until the EPA issues a final decision on the extension requests. On October 5, 2022, SIGECO received a proposed conditional approval of its extension request for the A.B. Brown facility. Both the Culley East and A.B. Brown facility have been taken out of service in a timely manner per the commitments made to the EPA in the extension requests filed for both ponds. The Culley West pond was closed under CCR provisions applicable to inactive ponds, and closure activities were completed in December 2020. For further discussion about Indiana Electric’s ash ponds, see Note 14(d) to the consolidated financial statements.
On April 25, 2024, the EPA released its final Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities; Legacy CCR Surface Impoundments rule (CCR Legacy Rule), which was published in the federal register in May 2024. The CCR Legacy Rule requires companies to investigate previously closed impoundments that were used historically for ash disposal or locations which have had ash placed on them in amounts set forth in the CCR Legacy Rule. The Registrants have completed their preliminary review of potential sites that will require further investigation under the CCR Legacy Rule and identified certain sites in Indiana for further evaluation. For further discussion about Indiana Electric’s sites identified pursuant to the CCR Legacy Rule, see Note 14(d) to the consolidated financial statements.
Liability for Remediation
CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of “hazardous substances” into the environment. Classes of PRPs include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is expressly excluded from CERCLA’s definition of a “hazardous substance,” in the course of the Registrants’ ordinary operations they do, from time to time, generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties, to take action in response to threats to the public health or the environment and to recover the costs they incur from the responsible classes of persons. Under CERCLA, the Registrants could potentially be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for associated response and assessment costs, including for the costs of certain health studies.
Liability for Preexisting Conditions
For information about preexisting environmental matters, see Note 14(d) to the consolidated financial statements.
HUMAN CAPITAL
CenterPoint Energy believes its employees are critical to safely delivering electricity and natural gas across its service territories and seeks to create an open and safe work environment. CenterPoint Energy’s core values-safety, integrity, accountability, initiative and respect-guide how it makes decisions and provide the foundation for a strong culture of ethics where employees are responsible for upholding these values and following CenterPoint Energy’s Ethics and Compliance Code.
The following table sets forth the number of employees by Registrant and reportable segment as of December 31, 2024:
Number of Employees Number of Employees Represented by Collective Bargaining Groups
Reportable Segment CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
Electric 3,184 2,839 - 1,699 1,511 -
Natural Gas 3,656 - 3,390 1,651 - 1,587
Corporate and Other (1)
2,032 - - 135 - -
Total 8,872 2,839 3,390 3,485 1,511 1,587
(1)Employees in the Corporate and Other segment provide services to the Electric and Natural Gas segments and the costs of these services have been charged directly to the Electric and Natural Gas segments using assignment methods that management believes are reasonable. For further information, see Note 18 to the consolidated financial statements.
CenterPoint Energy’s workforce includes 3,485 employees represented by collective bargaining agreements. For information about the status of collective bargaining agreements, see Note 8(j) to the consolidated financial statements.
Talent Attraction, Development and Retention. CenterPoint Energy’s human capital priorities include attracting, retaining and developing high performing talent through its talent management activities. CenterPoint Energy endeavors to attract quality candidates through its recruitment and selection processes. CenterPoint Energy recruits qualified employees regardless of race, gender, color, sexual orientation, age, religion, national origin, or physical or mental disability. The talent acquisition team actively promotes CenterPoint Energy on college campuses to create awareness of our offerings to engineering, finance and technical occupations, and maintains relationships with student organizations at many institutions throughout our footprint.
CenterPoint Energy takes a strategic approach to attracting, retaining, and developing its workforce. CenterPoint Energy’s strategy combines succession planning along with internal talent development as essential elements of overall workforce development. To support its commitment to delivering electricity and natural gas safely and reliably, CenterPoint Energy focuses on the continuous development of its greatest assets, its employees, to build a sustainable leadership pipeline. To meet the business's future needs, CenterPoint Energy’s goal is to create great leaders capable of developing their employees, while supporting the business goals and maintaining a high-performing workforce. CenterPoint Energy has a number of tools for leadership and employee development that expand opportunities available to employees. CenterPoint Energy conducts regular talent discussions, including succession planning with all levels of leadership to provide business continuity and identify its future leaders and opportunities. CenterPoint Energy invests in employee development throughout the year to align performance to business needs, drive development planning and contribute to career progression. CenterPoint Energy’s processes and progress are reviewed regularly for continuous improvement.
Engagement. CenterPoint Energy is dedicated to advancing an ethical and high performance work environment where business results are achieved through the experience, skills, abilities and talents of the whole workforce. CenterPoint Energy aims to create a workplace where every employee is engaged, aligned with our values, strategy, goals and priorities, and understands how each person contributes to the Company’s long-term performance. In 2024, CenterPoint Energy’s senior leadership team held quarterly town hall meetings with employees to share key Company updates, with employees across the Company participating in person or via video conference.
Compensation and Benefits. CenterPoint Energy is committed to providing its employees with competitive pay and benefits. Its compensation philosophy is to maintain employee total compensation that is competitive with the relevant markets, internally equitable, and based on company and individual performance. CenterPoint Energy expects that this will enable it to attract, motivate and retain employees with the skills and competencies necessary to achieve its business strategy. In addition to
competitive compensation, CenterPoint Energy provides its employees with a comprehensive benefits package designed to help employees stay healthy, care for their families, plan for the future and enjoy peace of mind. The benefits package includes medical, dental, vision, life, disability and accidental insurance coverage; retirement, company match savings plans; paid time off, parental leave, wellness and employee assistance programs. The employee wellness resources encompass support for mental, financial and physical health.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
(as of February 10, 2025)
Name Age Title
Jason P. Wells 47 President and Chief Executive Officer
Christopher A. Foster 46 Executive Vice President and Chief Financial Officer
Monica Karuturi 46 Executive Vice President and General Counsel
Jason M. Ryan 49 Executive Vice President, Regulatory Services and Government Affairs
Darin M. Carroll
48 Senior Vice President, Electric Business
Richard C. Leger
47 Senior Vice President, Natural Gas Business
Jason P. Wells has served as President and Chief Executive Officer of CenterPoint Energy and a member of the Board of Directors of CenterPoint Energy since January 5, 2024. Previously he served as President and Chief Operating Officer of CenterPoint Energy from May 2023 to January 2024; as President, Chief Operating Officer and Chief Financial Officer of CenterPoint Energy from January 2023 to May 2023; and as Executive Vice President and Chief Financial Officer of CenterPoint Energy from September 2020 to December 2022. Prior to joining CenterPoint Energy, Mr. Wells served as Executive Vice President and Chief Financial Officer of PG&E Corporation, a publicly traded electric utility holding company serving customers in Northern and Central California through its subsidiary Pacific Gas and Electric Company, from June 2019 to September 2020. He previously served as Senior Vice President and Chief Financial Officer of PG&E Corporation from January 2016 to June 2019 and as Vice President, Business Finance of Pacific Gas and Electric Company from August 2013 to January 2016. PG&E Corporation filed Chapter 11 bankruptcy on January 29, 2019 and successfully emerged from bankruptcy on July 1, 2020. He also served in various finance and accounting roles of increasing responsibility at Pacific Gas and Electric Company. Mr. Wells earned his bachelor’s degree and master’s degree in accounting, both from the University of Florida. He is a certified public accountant. Mr. Wells serves on the Executive Committee and Board for the Greater Houston Partnership, the Advisory Board of the Kinder Institute for Urban Research at Rice University, and the Boards of Central Houston, Inc. and M.D. Anderson Cancer Center.
Christopher A. Foster has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since May 2023. Previously, he served as Executive Vice President and Chief Financial Officer of PG&E Corporation, a publicly traded electric utility holding company serving customers in Northern and Central California through its subsidiary Pacific Gas and Electric Company, from March 2021 to May 2023. He previously served in various positions of increasing responsibilities at PG&E since 2011, including as Vice President and Interim Chief Financial Officer from September 2020 to March 2021, and Vice President, Treasury and Investor Relations from March 2020 to September 2020. PG&E Corporation filed Chapter 11 bankruptcy on January 29, 2019 and successfully emerged from bankruptcy on July 1, 2020. He earned his bachelor’s degree from Michigan State University. Mr. Foster serves on the Board of Exploratorium, a San Francisco-based science and technology museum, as well as the Board of Directors of the Houston Parks Board.
Monica Karuturi has served as Executive Vice President and General Counsel of CenterPoint Energy since January 2022. She previously served as Senior Vice President and General Counsel from July 2020 to January 2022; as Vice President and Deputy General Counsel from April 2019 to July 2020; as Vice President and Associate General Counsel - Corporate and Securities from October 2015 to April 2019; and as Associate General Counsel - Corporate from September 2014 to October 2015. Prior to joining CenterPoint Energy, Ms. Karuturi served as counsel for LyondellBasell Industries for corporate and finance matters and strategic transactions. Ms. Karuturi earned her bachelor’s degree from Brown University, master’s degree in health policy and management from Columbia University, and juris doctorate from Georgetown University Law Center. Ms. Karuturi was appointed as a Commissioner of the Texas Access to Justice Commission by the Texas Supreme Court in June 2015 and served in this capacity until June 2021. She was also appointed as Chair of the Houston Bar Foundation in 2021 and served until December 2024. She currently serves as a member of the Board of Directors of the Houston Zoo.
Jason M. Ryan has served as Executive Vice President, Regulatory Services and Government Affairs of CenterPoint Energy since January 2022. He previously served as Senior Vice President, Regulatory Services and Government Affairs from July 2020 to January 2022; as Senior Vice President and General Counsel from April 2019 to July 2020; as Senior Vice
President, Regulatory and Government Affairs from February 2019 to April 2019; as Vice President of Regulatory and Government Affairs and Associate General Counsel from March 2017 to February 2019; and as Vice President and Associate General Counsel from September 2014 to March 2017. He was appointed to the Texas Diabetes Council by Texas Governor Perry in 2013 for a term ending in 2019; he was reappointed by Texas Governor Abbott in 2019 for a term ending in 2025. Mr. Ryan earned his bachelor’s degree from the Texas McCombs School of Business and juris doctorate from the University of Texas School of Law. Mr. Ryan currently serves on the boards of the Lone Star Flight Museum and the Association of Electric Companies of Texas and on the advisory board of the Strategic AI Program at Houston Christian University. He also serves on the executive committee of the legal committee of the American Gas Association.
Darin M. Carroll has served as Senior Vice President, Electric Business of CenterPoint Energy since July 2024. He previously served as Senior Vice President, Natural Gas Business from January 2023 to July 2024; as Senior Vice President, Operations Support from January 2022 to January 2023; and as Vice President, Operations Support from February 2019 to January 2022. Prior to Vectren’s acquisition by CenterPoint Energy, Mr. Carroll served as Director, Operations from February 2014 to February 2019 of Vectren. He earned his bachelor’s degree from the University of Southern Indiana. Mr. Carroll currently serves on the Executive Committee and Board of Directors of the Junior Achievement of Southeast Texas and as a member of the Research Advisory Committee of the Electric Power Research Institute. He has also previously been on the Board of Directors of the American Gas Association, the Southern Gas Association, and the Guardianship Services of Southwestern Indiana, as well as a trustee of the American Gas Foundation. Mr. Carroll has also served as a member of the Indiana Energy Association Gas Operations Committee, Midwest Energy Association Electric Operations Steering Committee, and American Gas Association Field Operations Committee. He earned a bachelor’s degree from the University of Southern Indiana in Evansville, Indiana.
Richard C. Leger has served as Senior Vice President, Natural Gas Business of CenterPoint Energy since January 2025. Mr. Leger previously served in various positions of increasing responsibilities at CenterPoint Energy since 2001, including as Interim Senior Vice President, Natural Gas Business from July 2024 to December 2024; as Senior Vice President, Indiana Electric from January 2022 to July 2024; as Vice President of Gas Operations, Indiana and Ohio from February 2019 to January 2022; as Director, District Operations for Little Rock, Arkansas from November 2015 to February 2019; as Director, Regulatory Affairs from August 2011 to November 2015; and as Manager, Sales and Conservation Improvement Program from August 2010 to August 2011. Mr. Leger currently serves as a board member for the American Gas Association, Southern Gas Association, United Way of Southwestern Indiana and Golf Gives Back. He is also a trustee of the American Gas Foundation and a former chair of the Southeast Energy Efficiency Alliance. In addition, Mr. Leger served six years in the Louisiana Army National Guard. He earned two bachelor’s degrees in accounting and marketing from McNeese State University.

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ITEM 1A. RISK FACTORS
Item 1A.Risk Factors
CenterPoint Energy is a holding company that conducts all of its business operations through subsidiaries, primarily Houston Electric, CERC and SIGECO. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this combined report on Form 10-K, summarizes the principal risk factors associated with the holding company and the businesses conducted by its subsidiaries. However, additional risks and uncertainties either not presently known or not currently believed by management to be material may also adversely affect CenterPoint Energy’s businesses. For other factors that may cause actual results to differ from those indicated in any forward-looking statement or projection contained in this combined report on Form 10-K, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Certain Factors Affecting Future Earnings” in Item 7, which should be read in conjunction with the risk factors contained in this Item 1A. Carefully consider each of the risks described below, including those relating to Houston Electric, LLC and CenterPoint Energy Resources Corp., which, along with CenterPoint Energy, Inc., are collectively referred to as the Registrants. Unless the context indicates otherwise, where appropriate, information relating to a specific registrant has been segregated and labeled as such and specific references to Houston Electric and CERC in this section also pertain to CenterPoint Energy. In this combined report on Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries.
Risk Factors Affecting Operations
Electric Generation, Transmission and Distribution (CenterPoint Energy and Houston Electric)
Disruptions at power generation facilities, generation inadequacy or directives issued by regulatory authorities could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and adversely affect their reputation, financial condition, results of operations and cash flows.
Houston Electric owns the transmission and distribution infrastructure in its service territory that delivers electric power to its customers, but it does not own or operate any power generation facilities, except for its operation of TEEEF. Indiana Electric owns and operates power generation facilities in addition to the transmission and distribution infrastructure in its service territory. Both Houston Electric and Indiana Electric must follow the directives issued by their respective independent system operator, ERCOT and MISO, respectively. ERCOT and MISO have and may in the future issue directives requiring members to implement controlled outages as a result of an emergency or reliability issues, and Houston Electric has faced and may in the future face challenges to its planning and preparation for such directives and its implementation of Load Shed, including, for example, allegations that it had discretion as to how to shed load and which customers experienced outages and the duration of those outages. As a result, claims and lawsuits could be filed against Houston Electric and Indiana Electric for personal injury, property damage or other damage or loss as a result of their respective Load Shed planning, preparation, implementation, and decisions in order to meet the directives of ERCOT and MISO, respectively. For example, in February 2021, the ERCOT regulated Texas electric system experienced extreme winter weather conditions and an unprecedented power generation shortage. The amount of electricity generated by the state’s power generation companies was insufficient to meet the amount demanded by customers. This resulted in ERCOT directing TDUs to significantly Load Shed, which caused customer outages across the ERCOT electric grid of Texas, including in Houston Electric’s service territory. See Note 7 to the consolidated financial statements and “- Houston Electric’s use of TEEEF ...” for further information. If power generation capacity is severely disrupted or is inadequate for any reason in the future, Houston Electric’s or Indiana Electric’s transmission and distribution services may be diminished or interrupted. Further, as with the lawsuits filed in the aftermath of the February 2021 Winter Storm Event, claims and lawsuits could be filed against the Registrants, and our reputation, financial condition, results of operations and cash flows could be adversely affected.
Additionally, Indiana Electric’s generating facilities and the generating facilities that supply the power transmitted by Houston Electric and Indiana Electric are subject to operational risks that have and may in the future result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchase power costs. For example, in June 2022, Culley 3, a coal-fired generation unit, experienced a boiler feed pump turbine failure that caused the unit to be out of service for nearly nine months. In this time frame, CenterPoint Energy purchased energy on the open market. Such open market purchases have and may again result in increased costs and have an adverse impact on our operations, financial condition, results of operations and cash flows. Further, Indiana Electric is party to a number of PPAs with third parties. Indiana Electric’s power generation may be disrupted or otherwise insufficient if third parties do not deliver required power under our PPAs. These operational risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator error; aging infrastructure; interruption of fuel supply or increased prices of fuel as a result of, among other things, contract expirations, inflation and/or tariffs; disruptions in the delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; or natural disasters, all of which could adversely affect Indiana Electric’s and Houston Electric’s businesses. Further, Indiana Electric currently relies on coal for a portion of its generation capacity. Indiana Electric purchases the majority of its coal supply from a single, unrelated party and, although the coal supply is under long-term contract, the loss of this supplier or transportation interruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s financial condition, results of operations and cash flows. In 2021 and part of 2022, Indiana Electric experienced coal supply shortages due to labor shortages that the coal industry experienced. While the coal supply shortage that Indiana Electric experienced did not impact its ability to deliver electricity to its customers, labor shortages as well as supply shortages in the future, whether caused by insufficient supply or supplier bankruptcy or other regulatory and supply issues in the mining industry, may lead to increased cost and have an adverse impact on our operations, financial condition, results of operations and cash flows. See “- Disruptions to the global supply...” As Indiana Electric continues its generation transition and more renewable energy sources come online, Indiana Electric’s generating facilities may experience unanticipated disruptions as a result of renewable supply shortages, including, but not limited to, adverse weather such as cloudy or windless days. Additionally, such disruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s financial condition, results of operations and cash flows.
The operations of Houston Electric and Indiana Electric are subject to the usual hazards associated with high-voltage electricity transmission and distribution, including inclement or severe weather, natural disasters, including wildfires, mechanical failure, contact with electrified facilities by people, equipment, and debris, unscheduled downtime, equipment
interruptions, contamination, remediation, explosions, fires, chemical spills, discharges or releases of toxic or hazardous substances, and other environmental risks. Such hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment, including loss of transmission and distribution lines and related equipment and damage to solar panels, and environmental damage, and may result in suspension of operations, disruption of service to customers, and the imposition of civil or criminal penalties. For example, Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system, resulting in a substantial number of its customers (peaking at more than 2.1 million customers out of 2.8 million customers) being without power, many for extended periods of time. Houston Electric and Indiana Electric maintain property and casualty insurance but are not fully insured against all potential hazards incident to their businesses.
Indiana Electric’s execution of its generation transition plan, including its IRP, is subject to various risks, including timely recovery of capital investments and increased costs and risks related to the timing and cost of development and/or construction of new generation facilities.
Indiana requires each electric utility to perform and submit an IRP to the IURC every three years, unless extended, that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable electric service for the next 20-year period. Indiana Electric has used past IRPs and will continue to use future IRPs to evaluate its mix of generation resources. Indiana Electric engages with the communities it serves, its regulators and third-parties in developing its generation transition plan. Recent IRPs have demonstrated Indiana Electric can most cost effectively serve its customers by transitioning its generation fleet to a wider mix of resources, including renewables. For example, 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 is continuing its plan to transition generation resources away from coal-fired generation to a more sustainable portfolio of resources, including renewables. While the IURC does not approve or reject Indiana Electric’s IRP, the IURC does comment on the IRP. Indiana Electric is required to obtain a CPCN prior to constructing or acquiring generating resources. Indiana Electric also obtains IURC approval of PPAs and DSM plans to help ensure cost recovery.
Indiana Electric must manage several risks associated with its generation transition plan. The IURC may delay providing comments on an IRP, requiring Indiana Electric to either wait for comments or proceed to implement its IRP without IURC comments. The IURC comments may raise concerns with Indiana Electric’s IRP that make it difficult to obtain approval of the generation transition plan if not addressed. There is no guarantee that the IURC will approve Indiana Electric’s requests to implement part of its generation transition. If Indiana Electric fails to receive IURC approvals necessary to acquire the projects or resources identified in its IRP, Indiana Electric may not be able to implement its generation transition plan in a timely manner or at all. Additionally, projected changes in how renewable and battery storage resources are accredited to meet MISO’s planning reserve margin requirement make it less economic to pursue these resources in the future. In connection with its IRPs, Indiana Electric’s determinations with respect to the appropriate mix of generation resources may change from plans that were previously announced. If Indiana Electric is unable to implement its generation transition plan, it may have an adverse effect on CenterPoint Energy’s ability to execute on its net zero and GHG emissions reduction goals, its goal to exit the coal plants that Indiana Electric operates, its growth strategy, achieve its financial goals, and otherwise impact results of operations and cash flows.
Even if a generation project is approved, risks associated with the development or construction of any new generation exist, including new legislation or governmental action restricting or delaying new generation, moratorium legislation, the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays, project scope changes, and cost overruns and the ability to meet capacity requirements. For example, in January 2025, President Trump signed executive orders that, among other things, temporarily halted certain federal government agencies from issuing approvals, permits and loans for onshore wind projects pending the completion of certain assessments and reviews, and pause the disbursement of funds appropriated through the IRA and the Infrastructure Investments and Jobs Act. As an additional example, the developers of a 130 MW Pike County Solar project informed Indiana Electric that, due to delays in the MISO interconnection queue and inflationary pressures, costs exceeded the agreed upon levels in the BTA. After negotiations, Indiana Electric and the developer were not able to agree upon updated pricing. As a result, on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate the BTA. Further, tariffs, as well as any new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could adversely affect our ability to develop and construct new generation, including our ability to procure the resources needed for such development and construction. For example, on February 6, 2025, the EPC contractor for Indiana Electric’s proposed natural gas combustion turbines provided a notice to Indiana Electric that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project. For additional information, see “- Disruptions to the global supply...” Furthermore, we have begun to acquire and/or develop additional solar and wind facilities as part of our capital plan.
However, we have not yet entered into definitive agreements with developers for the acquisition and/or development of all of the additional projects, and we face significant competition with other bidders for a limited number of such generation facilities that developers plan to construct and for solar panels. For additional information, see “- Increases in the cost or reduction in supply ...” The number of available projects is further limited by the MISO interconnection queue due to potential interconnection costs that may render projects infeasible. As a result, suitable generation facility project candidates or resources necessary to construct such projects may not be available on terms and conditions we find acceptable, or the expected benefits of a completed facility may not be realized fully or at all, or may not be realized in the anticipated timeframe. If Indiana Electric was unable to meet its generation needs as a result of project delays or cancellations, it would be required to buy the necessary capacity and electricity on the open market. Such open market purchases may result in increased costs and may have an adverse impact on our operations, financial condition, results of operations and cash flows. If we are unable to complete or acquire such generation facilities or resources, or if they do not perform as anticipated, our future growth, financial condition, results of operations and cash flows may be adversely affected.
Houston Electric’s receivables are primarily concentrated in a small number of REPs, and any delay or default in payments of these receivables could adversely affect Houston Electric’s financial condition, results of operations and cash flows.
Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity. As of December 31, 2024, Houston Electric provided electric delivery service to approximately 67 REPs. Adverse conditions, including, but not limited to, the February 2021 Winter Storm Event or other extreme weather (which may result in abnormal power prices), structural problems in the market served by ERCOT, the impact of pandemic health events or similar occurrences, mismanagement by the REPs, inflation or financial difficulties of one or more REPs, have and may in the future impair the ability of these REPs to pay for Houston Electric’s services or cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms to otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments relating to services provided prior to any shift to another REP or provider of last resort. Houston Electric’s PUCT-approved tariff outlines the remedies available to Houston Electric in the event that a REP defaults on amounts owed. Among the remedies available to Houston Electric are seeking recourse against any cash deposit, letter of credit, or surety bond provided by the REP or implementing mutually agreeable terms with the REP. Another remedy is to require that customers be shifted to another REP or a provider of last resort. Houston Electric thus incurs risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are due from affiliates of NRG and Vistra Energy Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2024 was $263 million. Approximately 37% and 21% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s financial condition, results of operations and cash flows. If a REP was 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 regarding prior payments Houston Electric had received from such REP. For example, following the February 2021 Winter Storm Event, multiple REPs filed for bankruptcy. We are currently recording the amounts owed by these REPs as a regulatory asset for bad debt expenses, which is subject to a reasonableness review by the PUCT in our current base rate case. As of December 31, 2024 and 2023, as authorized by the PUCT, CenterPoint Energy and Houston Electric recorded a regulatory asset of $8 million for bad debt expenses resulting from REPs’ defaults on their obligations to pay delivery charges to Houston Electric, net of collateral. There is no guarantee that we will be able to recover any or all of the regulatory asset in our next base rate case. See “- Rate regulation of Registrants’ Electric ...” For further information on certain of Houston Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report.
Houston Electric’s use of TEEEF is subject to various risks, including failure to obtain and deploy sufficient TEEEF resources, potential performance issues and allegations about Houston Electric’s procurement and deployment of the resources (including the planning, execution and effectiveness of the same), regulatory and environmental requirements, and timely recovery of capital.
Following the February 2021 Winter Storm Event, the Texas legislature passed a law, effective September 1, 2021, that allows TDUs, such as Houston Electric, to lease and temporarily operate back-up generation resources during widespread power outages where ERCOT has ordered a TDU to Load Shed or the TDU’s distribution facilities are not being fully served by the bulk power system under normal operations. In response to this legislation, Houston Electric entered into two leases for large 27 MW to 32 MW TEEEF (temporary generation) and medium five MW TEEEF. In 2023, the Texas legislature amended the law to allow wider use of TEEEF, including in response to a significant power outage affecting a significant number of distribution customers that has lasted or is expected to last for at least six hours, affecting distribution customers in an area for
which the governor has issued a disaster or emergency declaration, affecting distribution customers served by a radial transmission or distribution facility that creates a risk to public health or safety and that has lasted or is expected to last for at least 12 hours, or creating a risk to public health or safety because it affects a critical infrastructure facility that serves the public. Pursuant to the amendment, the Texas Division of Emergency Management, ERCOT, or the executive director of the PUCT may also determine that a power outage other than one described above is a significant power outage for purposes of use of TEEEF. In response to this amendment, Houston Electric entered into additional leases for small 200-kilowatt to one MW TEEEF.
If Houston Electric is unable to deploy a sufficient number of TEEEF resources in time to respond to a particular event (including as a result of re-leasing TEEEF to third parties or similar transactions, as described further below, or if leasing certain TEEEF becomes prohibited by law, as further described below); if TEEEF resources fail to perform, or are perceived to fail to perform, as intended; if Houston Electric is otherwise unable, or perceived as unable, to provide back-up generation resources and restore power as intended; or if the use of TEEEF resources or their failure to perform causes or is alleged to cause any personal injury, property damage, or other damage or loss due to allegations Houston Electric failed to deploy such units reasonably or effectively and failed to respond to particular power outages, Houston Electric could be subject to claims, demands, litigation, liability, regulatory scrutiny, and loss of reputation. For example, various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl and the efforts made by Houston Electric to prepare for, and respond to, this event, including, among other things, Houston Electric’s procurement of TEEEF. Texas Lieutenant Governor Patrick has publicly urged the PUCT to hold Houston Electric, rather than ratepayers, responsible for paying approximately $800 million, which, as detailed below, was the amount the PUCT had previously approved Houston Electric to recover from ratepayers relating to Houston Electric’s leasing of TEEEF. Additionally, legislation has been proposed in Texas to, among other things, require the PUCT to review TEEEF leased by TDUs, disallow any leases that do not conform to the terms of the proposed legislation (which include, among other things, requirements relating to the speed with which TEEEF may be deployed), disallow recovery of costs associated with such disallowed leases, and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl, including with respect to its TEEEF resources. There are significant uncertainties around these inquiries, investigations and proposed legislation and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed; whether changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom; or whether it will be viable for Houston Electric to continue leasing TEEEF. If it is no longer viable for Houston Electric to lease TEEEF at the same or similar scale at which it currently leases such resources and ERCOT issues a directive requiring TDUs to Load Shed or other conditions occur that could be, or are perceived to have the potential to be, addressed by Houston Electric’s deployment of TEEEF, Houston Electric could be subject to claims, demands, litigation, liability, regulatory scrutiny and loss of reputation. Additionally, while Houston Electric has insurance coverage and indemnity rights for its use of TEEEF resources, if its insurers or indemnitors fail to meet their indemnity obligations, Houston Electric could be liable for personal injury, property damage, or other damage or loss. For further information, see “- Hurricane Beryl caused severe disruptions...,” “- We are involved in numerous legal proceedings...” and “- Our insurance coverage may not...”
As noted above, the legislation allowing TDUs to lease and operate TEEEF prescribes specific and limited use for TEEEF, and Houston Electric’s TEEEF have limited generation capacity, such that in future events customers could still be without power despite deployment of TEEEF resources. Further, TEEEF resources are subject to various environmental regulations and permitting requirements, which could have an impact on Houston Electric’s ability to use these units. If Houston Electric is not in compliance with any environmental regulation or permitting requirement, Houston Electric could be subject to further potential liability. The use of TEEEF is also subject to various other requirements, and failure to comply with them could subject Houston Electric to additional liability as well as challenges to its use of TEEEF in general.
In April 2023, the PUCT approved revenue recovery of $39 million of TEEEF costs incurred in 2021, and in October 2023, an agreement with intervenors was reached with respect to Houston Electric’s second TEEEF filing for revenue recovery of $153 million ($114 million incremental to the prior filing) of TEEEF costs incurred through December 31, 2022, and the agreement was approved by PUCT in February 2024. On September 11, 2024, the TCA filed a complaint with the PUCT requesting that the PUCT modify its rulings with respect to its prior decisions related to the TEEEF filings made in 2022 and 2023. Specifically, TCA requested that the PUCT end cost recovery and return on investment on all the large 32 MW and 5 MW TEEEF units approved in docket 53442. On October 2, 2024, Houston Electric filed a response to the TCA complaint and requested that the complaint be dismissed due to the principles of res judicata and collateral estoppel. On October 8, 2024, TCA supplemented its complaint, and on October 9, 2024, PUCT staff filed a statement of position stating that Houston Electric’s response provided a strong argument for dismissal of the complaint, but also stating that it would be prudent to have a thorough legal argument from TCA. On October 10, 2024, PUCT issued Order No. 2 finding the TCA complaint insufficient and
requiring supplemental information or amendment from TCA by October 24, 2024; TCA filed supplemental information on October 24, 2024 and indicated it was prepared to submit supplemental evidence, but only in camera. On October 25, 2024, PUCT issued Order No. 3 in which TCA’s request for confidentiality with regard to its membership information was appropriate; Order No. 3 entered a protective order to govern the use of confidential materials in this docket. On November 13, 2024 TCA responded to Order No. 3 and repeated its offer to submit membership information in camera which the ALJ considered to be a motion for rehearing. On November 14, 2024, PUCT issued Order No. 4 which denied the motion to reconsider and extended the prior deadline to file supplemental information to December 13, 2024. On December 16, 2024, PUCT issued Order No. 5 granting waiver of the requirement for informal disposition and soliciting PUCT staff recommendation by January 16, 2025. On January 16, 2025, PUCT staff filed a supplemental recommendation recommending that TCA had not met the requirement to first present its complaint to the City of Houston prior to presenting it to the PUCT. On January 17, 2025 the case was abated until February 28, 2025 to enable TCA to present its complaint to the City of Houston.
Despite the recovery of certain TEEEF costs in the past, there can be no assurance that Houston Electric will seek to or be able to recover certain future TEEEF costs or be able to retain those costs previously approved for recovery. For example, on August 28, 2024, Houston Electric announced its proposal to forego approximately $110 million of profit related to its storm hardening and TEEEF efforts, which would be represented in part by Houston Electric not filing, beginning in 2028, for approximately $40 million in anticipated equity profit associated with Load Shed orientated TEEEF leased by Houston Electric through the remaining regulatory life of the leases in 2032 as new dispatchable generation is likely to come online in the state of Texas as a result of the Texas Energy Fund. Additionally, as noted above, legislation has been proposed in Texas to disallow recovery of costs associated with such disallowed leases and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. If Houston Electric is unable to recover or must return any or certain of its TEEEF costs our financial condition, results of operations and cash flows may be adversely affected. For further information, see “- Rate regulation of Registrants’ Electric...”, “- Our insurance coverage may not...” and “- We are subject to operational...”
On December 19, 2024, Houston Electric announced a proposal to release Houston Electric’s 15 large 27 MW to 32 MW TEEEF units to the San Antonio area prior to the summer of 2025. The proposal is intended to help ERCOT address a potential energy shortfall and Load Shed risk and to provide additional electric generation capacity to support growing energy demand in the greater San Antonio region. Under the proposal, Houston Electric would not receive revenue or profit from ERCOT and would also not charge Houston-area customers for these TEEEF units for the period they are in San Antonio serving ERCOT, which is currently expected to be for a period of up to two years. Houston Electric anticipates receiving revenues from one or more future transactions after the period the units are released to temporarily serve the energy need in the San Antonio area, and would therefore plan to continue to not charge customers for these units for future periods. As of the date of the filing of this Form 10-K, Houston Electric estimates that the value of the TEEEF units to be removed from the rate base as a result of the aforementioned proposal will be approximately $375 million. The proposal has not been finalized and is subject to the negotiation of definitive documentation among the relevant parties, as well as being subject to the approval of ERCOT and other stakeholders. It is not certain that mutually agreeable definitive documentation will be entered into at all or that all approvals will be obtained. Assuming that a definitive agreement is executed and that all necessary transaction approvals are received, this proposal is expected to result in a reduction to Houston Electric’s customers’ bills that Houston Electric would propose to the PUCT in the spring of 2025. Nevertheless, there can be no assurance that Houston Electric will be able to finalize the proposal. If the proposal is not finalized, it may have an adverse effect on our reputation and customer satisfaction, as well as potentially lead to negative consequences from regulatory authorities or other public authorities. Additionally, suitable future transactions may not be available on terms and conditions we find acceptable, or the expected benefits of Houston Electric’s proposal to release its 15 large 27 MW to 32 MW TEEEF units to San Antonio or any completed future transactions may not be realized fully or at all, or may not be realized in the anticipated timeframe, which could adversely impact our business, reputation, financial condition, results of operations and cash flows. Finally, if such transactions are successful and thereby result in Houston Electric having fewer TEEEF units to deploy in its own service territory, and if ERCOT issues a directive requiring TDUs to Load Shed or other conditions occur that could be, or are perceived to have the potential to be, addressed by Houston Electric’s deployment of TEEEF, Houston Electric could be subject to claims, demands, litigation, liability, regulatory scrutiny and loss of reputation.
Hurricane Beryl caused severe disruptions to our operations, customers and markets in certain of our service territories and could have a material adverse impact on our financial condition, results of operations, cash flows and liquidity.
In July 2024, Hurricane Beryl made landfall in Texas, bringing sustained winds, storm surges and torrential rain, which impacted our operations, customers and personnel in our Texas Gulf Coast markets. Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system, resulting in a substantial number of its customers (peaking at more than 2.1 million customers out of 2.8 million customers) being without power, many for extended periods of time.
The total cost for the restoration of Houston Electric’s electric delivery facilities as a result of Hurricane Beryl is currently estimated to be $1.1 billion, excluding carrying costs, but such estimate is preliminary and restoration costs could vary from that estimate. Houston Electric believes it is entitled to recover prudently incurred storm restoration costs in accordance with applicable regulatory and legal principles. However, neither the amount nor timing of the recovery is certain. Houston Electric’s failure to recover costs incurred as a result of Hurricane Beryl could adversely affect our liquidity, cash flows and financial condition.
Various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl and the efforts made by Houston Electric to prepare for, and respond to, this event, including, among other things, the electric service outage issues. Moreover, additional governmental and regulatory agencies and other entities may conduct such inquiries and investigations, as well. On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl. Certain government officials have also made public statements calling for, and proposed legislation seeking to require, Houston Electric to pay certain costs related to TEEEF. For more information regarding TEEEF-related risks, see “- Houston Electric’s use of TEEEF ...” There are significant uncertainties around these inquiries and investigations and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed or changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom. If these or other inquiries, investigations or reviews ultimately result in changes to Houston Electric’s system, service territories, operations and/or regulatory treatment, such changes could have an adverse impact on our business, results of operations, cash flows and financial condition. Further, on January 22, 2025, a putative shareholder of CenterPoint Energy, Donel Davidson, filed a derivative petition in Harris County District Court, Texas, alleging breach of fiduciary duty and unjust enrichment on behalf of CenterPoint Energy against certain of its current and former directors and officers citing, in part, the topics of these inquiries and investigations. The action seeks to recover damages and other relief from the defendants on behalf of CenterPoint Energy. Additionally, on February 12, 2025, a second putative shareholder of CenterPoint Energy made a demand on the Board to investigate the same basic allegations raised in the derivative petition filed by Donel Davidson.
CenterPoint Energy and Houston Electric are subject to current and potential future litigation and claims arising out of Hurricane Beryl, which litigation and claims could include allegations of, among other things, personal injury, property damage, various economic losses in connection with loss of power, unlawful business practices, and others. As of December 31, 2024, five lawsuits had been filed against CenterPoint Energy and/or Houston Electric in the District Courts of Harris County, including three putative class actions claiming losses due to power outages following Hurricane Beryl. Each class action seeks damages in excess of $100 million for, among other things, business interruption, property damage and loss, cost of repair, loss of use and market value, lost income, nuisance, extreme mental anguish and/or punitive damages. CenterPoint Energy and its subsidiaries have general and excess liability insurance policies that provide coverage for third party bodily injury and property damage claims. Given the nature of some allegations, it is possible that the insurers could dispute coverage for some types of claims or damages that may be alleged by plaintiffs, and CenterPoint Energy has received from two insurers denial of indemnity coverage in the putative class actions based on the failure to supply exclusion. Those insurers have also reserved their rights with respect to coverage in those actions. CenterPoint Energy and Houston Electric intend to continue to pursue all available insurance coverage for all of these matters. While CenterPoint Energy and Houston Electric intend to vigorously defend themselves against the lawsuits, final resolution of these matters, or any potential future claims or liabilities, may require expenditures that may be in excess of established insurance or reserves and may have a material adverse effect on the Registrants’ financial condition, results of operation, cash flows and liquidity.
Increases in the cost or reduction in supply of solar energy system components due to tariffs or trade restrictions imposed by the U.S. government may have an adverse effect on our business, financial condition and results of operations.
China is a major producer of solar panels and other solar products. Certain solar cells, modules, laminates and panels from China are subject to various antidumping and countervailing duty rates, depending on the exporter supplying the product, imposed by the U.S. government as a result of determinations the United States was materially injured as a result of such imports being sold at less than fair value and subsidized by the Chinese government. Additionally, in March 2022, the DOC announced it would initiate an investigation into whether imports of solar cells and panels produced in Cambodia, Malaysia, Thailand and Vietnam are circumventing U.S. rules and laws, such as antidumping and countervailing duty rates, which impose a tariff on imports of solar cells and panels manufactured in China. On August 18, 2023, the DOC announced its final determination that five of the eight companies investigated were attempting to bypass U.S. duties by doing minor processing in Southeast Asian countries before shipment to the United States. On May 15, 2024, based on a petition filed by the American Alliance for Solar Manufacturing Trade Committee, the DOC announced the initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells from Cambodia, Malaysia, Thailand, and Vietnam. On October 1, 2024, the DOC’s preliminary countervailing duty determination affirmed the petition and established preliminary duty rates. A final
determination is expected in the first quarter of 2025. On November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates. A final determination is expected in the second quarter of 2025. In addition, in December 2021, the United States enacted the Uyghur Forced Labor Prevention Act, which bans goods from China’s Xinjiang region due to the use of forced labor. Continuing tensions between the United States and China may lead to restrictions in trade between the two countries or new legislation, tariffs or bans. Furthermore, President Trump has expressed a desire to impose substantial new or increased tariffs on foreign imports into the United States, and in February 2025, President Trump imposed tariffs on several countries (the effectiveness of tariffs imposed on certain countries was subsequently delayed until March 2025) and certain imports into the United States. These tariffs, as well as new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could further negatively impact the supply of solar panels. In addition to supply reductions, these or similar duties, legislation and other measures have and may in the future also put upward pressure on prices of these solar energy products, which may reduce our ability to acquire these items in a timely and cost-efficient manner. If we or the developers we are working with are unable to secure such solar energy products in a timely and cost-efficient manner, we may be required to seek additional regulatory review and approvals and/or be forced to delay, downsize and/or cancel solar projects, in which case we may not be able to fully execute on our ten-year capital plan or achieve our net zero and GHG emissions reduction goals. We have experienced project delays due to developers of our projects being unable to acquire solar panels due to supply chain constraints. Additionally, delays or cancellations by developers of third-party solar power facilities expected to interconnect with CenterPoint Energy’s and Houston Electric’s system may have adverse impacts, such as delayed or reduced potential future revenues. We cannot predict what additional actions the U.S. government may adopt with respect to tariffs, trade agreements or other trade regulations in the future or what actions may be taken by other countries in retaliation for such measures. If the DOC imposes tariffs on solar panels as a result of its findings or other additional measures are imposed, our business, financial condition and results of operations may be adversely affected.
The occurrence of extreme weather events, including winter storms and record hot temperatures, or other causes could lead to additional reforms to the Texas electric market, some measure of which, if implemented, could have an adverse impact on Houston Electric.
During and in the aftermath of the February 2021 Winter Storm Event, the Texas legislature revised applicable statutes and granted the PUCT and ERCOT additional regulatory authority, both oversight and enforcement, that focuses on ensuring ERCOT market participants, including power generation facilities and TDUs (like Houston Electric), have adopted sufficient winterization standards and protection. Houston Electric believes it is in compliance with the requirements applicable to it. If any additional protections are required in the future as a result of additional extreme weather events or other causes, complying with these new protections may increase the cost of electricity, which could adversely affect Houston Electric’s results of operations. Any potential decreases in customer usage due to higher electricity prices charged by REPs may not result in increased base rates charged by Houston Electric for its services until its next general base rate proceeding. For further information on Houston Electric’s regulatory proceedings, see “- Rate regulation of Registrants’ Electric...”
In addition, the PUCT and ERCOT continue to review, among other things, the appropriate reliability standard and market design for the Texas electric market. There are uncertainties whether any further changes will result from these discussions or other efforts. If there are changes to how the Texas electric market is structured or regulated, including as a result of Hurricane Beryl and related investigations, such changes could have an adverse impact on Houston Electric’s business, financial condition and results of operations. See Note 7 to the consolidated financial statements for further information.
Natural Gas (CenterPoint Energy and CERC)
Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for Natural Gas’ customers.
Natural Gas depends on third-party service providers to maintain an adequate supply of natural gas and for available storage and intrastate and interstate pipeline capacity to satisfy its customers’ needs, all of which are critical to system reliability. Substantially all of Natural Gas’ natural gas supply is purchased on intrastate and interstate pipelines. If Natural Gas is unable to secure an independent natural gas supply of its own or if third-party service providers fail to timely deliver natural gas to meet Natural Gas’ requirements, the resulting decrease in natural gas supply in Natural Gas’ service territories could have an adverse effect on its financial condition, results of operations, cash flows and reputation. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage deliveries or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, severe winter weather conditions, wildfires, acts of terrorism, human error or cyberattacks or changes in legislative or regulatory requirements, could also adversely affect Natural Gas’ businesses. Further, to the extent that Natural Gas’ natural gas requirements cannot be met
through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then Natural Gas’ operations could be negatively affected.
Natural Gas is subject to fluctuations in natural gas prices, which could affect the ability of its suppliers and customers to meet their obligations or may impact its operations, which could adversely affect CERC’s financial condition, results of operations and cash flows.
Natural Gas is subject to risk associated with changes in the price of natural gas. Significant increases in natural gas prices, such as those experienced during the February 2021 Winter Storm Event, might affect Natural Gas’ ability to collect balances due from customers and could create the potential for uncollectible accounts expense to exceed the recoverable levels built into tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which Natural Gas operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that Natural Gas’ suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase working capital requirements by increasing the investment that must be made to maintain natural gas inventory levels.
Natural Gas must compete with alternate energy sources, which could result in less natural gas delivered and have an adverse impact on CenterPoint Energy’s and CERC’s financial condition, results of operations and cash flows.
Natural Gas competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and natural gas marketers also compete directly with Natural Gas for natural gas sales to end users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass Natural Gas’ facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas delivered by Natural Gas as a result of competition with alternate energy sources may have an adverse impact on CenterPoint Energy and CERC’s financial condition, results of operations and cash flows.
Risk Factors Affecting Regulatory, Environmental and Legal Risks
Rate regulation of Registrants’ Electric and Natural Gas businesses may delay or deny their ability to earn an expected return and fully and timely recover their costs.
The Registrants’ Electric and Natural Gas businesses are regulated by certain municipalities, state commissions and federal agencies, such as FERC. Their rates are set in comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a designated test year (often either fully or partially historic), subject to periodic review and adjustments. Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of the Registrants’ control. Houston Electric and CERC, with respect to its Ohio gas territory, each filed rate cases during 2024. The Registrants can make no assurance that their or their subsidiaries respective base rate proceedings will result in requested or favorable adjustments to their rates, in full and timely cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings have caused in certain instances, and in the future could cause, the Registrants’ Electric and/or Natural Gas businesses to recover their investments below their requested levels, below the national average return for utilities or below recently approved return levels for other utilities in their respective jurisdictions. For instance, in the 2019 Houston Electric general rate case, Houston Electric filed a base rate case seeking approval for revenue increases of approximately $194 million and a 10.4% ROE, but after entering into a Stipulation and Settlement Agreement filed with the PUCT, Houston Electric received an overall revenue requirement increase of approximately $13 million and a 9.4% ROE. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their financial condition, results of operations and cash flows could be adversely affected. Further, the Registrants or their subsidiaries might be required to implement additional measures, such as the adoption of ring-fencing measures by Houston Electric in connection with its 2019 rate case proceeding. Such additional measures may adversely impact the Registrants’ businesses and could have an adverse effect on their financial condition, results of operations and cash flows.
The rates that Registrants’ Electric and Natural Gas businesses are allowed to charge may not match their costs at any given time, a situation referred to as “regulatory lag.” Regulatory lag has been and may be exaggerated in the future under certain circumstances, such as increased capital investments that are recovered in arrears, like those experienced in 2022, 2023 and early 2024. For example, the MPUC ordered extraordinary gas costs incurred in the February 2021 Winter Storm Event be recovered over a 63-month period from 2022 - 2027 and CERC forego recovery of the associated carrying costs. Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by the Registrants and their subsidiaries to reduce the effects of regulatory lag (for example, CSIA, DCRF, DRR, DSMA, GRIP,
RCRA, RRA, RSP, TCOS and TDSIC), such adjustment mechanisms are subject to the applicable regulatory body’s approval, which we cannot assure would be approved, and are subject to certain limitations that may reduce or otherwise impede the Registrants’ or their subsidiaries ability to adjust its rates or result in rates below those requested. Therefore, the Registrants can make no assurance filings for such mechanisms will result in favorable adjustments to rates or in full cost recovery. Further, from time to time, the Registrants’ regulators approve the issuance of securitization bonds in order to recover certain costs, including costs incurred as a result of severe weather or to recover stranded asset costs. The issuance of these securitization bonds may be delayed. If the issuance of securitization bonds is delayed, we may not be able to recover our costs in a timely manner, which could have an adverse effect on CenterPoint Energy’s, CERC’s, and Houston Electric’s financial condition, results of operations and cash flows.
Inherent in the regulatory process is some level of risk jurisdictional regulatory authorities may challenge the reasonableness or prudency of operating expenses incurred or capital investments made by the Registrants or their subsidiaries and deny the full recovery of their cost of service in rates. From time to time, these reviews and investigations have caused in certain instances, and in the future could cause, the Registrants to recover their costs or investments below their requested levels. For example, in October 2022, the MPUC issued a written order disallowing recovery of approximately $36 million of the $409 million originally requested by CERC in connection with its recovery of costs incurred as a result of the February 2021 Winter Storm Event. Notwithstanding the application of such rate adjustment mechanisms, the regulatory process by which rates are determined is subject to change as a result of legislative processes or rulemakings, as the case may be, and may not always be available or result in rates that will produce recovery of the Registrants’ or their subsidiaries’ costs or enable them to earn their authorized return. For example, legislation has been proposed in Texas to require the PUCT to review TEEEF leased by TDUs, disallow any leases that do not conform to the terms of the proposed legislation (which include, among other things, requirements relating to the speed with which TEEEF may be deployed), disallow recovery of costs associated with such disallowed leases, and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. There can be no assurances that Houston Electric will seek to or be able to recover certain future TEEEF costs or be able to retain those costs previously approved for recovery. For more information regarding TEEEF-related risks, see “- Houston Electric’s use of TEEEF ...” Additionally, changes to the rate case or interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact the Registrants’ ability to recover their costs in a timely manner. Additionally, decisions from regulators are typically subject to appeal, and any such appeal could further exacerbate regulatory lag and lead to additional uncertainty associated with rate case proceedings. The regulatory process may also be adversely affected by the political, regulatory and economic environment in the states in which we operate. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their financial condition, results of operations and cash flows could be adversely affected. For further information on rate case proceedings and interim rate adjustment mechanisms, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report.
The regulated utility businesses, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation, tariffs, high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect our business, financial position, results of operation or cash flows.
We face risks related to project siting, financing, construction, permitting, governmental approvals, public opposition, and the negotiation of project development agreements that may impede our development and operating activities.
Houston Electric, Indiana Electric and CERC own, develop, construct, manage and operate electric generation, transmission and distribution facilities or natural gas distribution facilities, as applicable. A key component of our growth is our ability to construct and operate these facilities. As part of these operations, we must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. We have previously experienced delays in receiving approval with regards to certain permits and licenses, and have had investigations and enforcement actions with regards to certain of our projects, which have caused delays to our projects in the past. Should we in the future be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits, or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, our future net income and cash flows could be reduced and our financial condition could be impacted. Any failure to negotiate successful project development agreements for new facilities with third parties could also have adverse effects. Additionally, our projects
have faced and may in the future face opposition from individuals, community organizations, environmental and other activist groups, and other public-interest entities.
We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could negatively affect our financial results.
The Registrants are subject to numerous legal proceedings, including lawsuits and environmental matters in addition to regulatory proceedings, the most significant of which are summarized in Note 14 to the consolidated financial statements. Litigation is subject to many uncertainties; recent trends have shown jury verdicts, settlements and other liability have been significantly increasing; and the Registrants cannot predict the outcome of all matters with assurance. Additionally, under some circumstances, the Registrants could potentially have claims filed against them or incur liabilities associated with assets and businesses no longer owned by them as a result of sales, divestitures or other transfers to third parties who may be unable to fulfill their indemnity obligations to the Registrants. Final resolution of these matters, or any potential future claims or liabilities, may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have an adverse effect on the Registrants’ financial results. For further information, see “- Our insurance coverage may not...”
Customers’, investors’, legislators’, regulators’ and creditors’ opinions of us are affected by many factors, including actual or perceived system reliability, the speed of our response to service interruptions, rates, our ability to successfully execute our capital plan, media coverage and actions by third parties, and negative opinions developed by such stakeholders could harm our reputation and have an adverse impact on our business, results of operations, cash flows and financial condition.
Our results are influenced by the expectations of our customers, investors, legislators, regulators and creditors. Those expectations are based, in part, on the actual or perceived reliability and affordability of our utility services. The speed with which we are able to respond effectively to electric outages, natural gas leaks or events and related accidents and similar interruptions caused by severe weather, physical or cybersecurity incidents or other unanticipated events, as well as our own or third parties’ actions or failure to act, can affect customer, regulator and legislator satisfaction. For example, various federal, state and local governmental and regulatory agencies and other entities have called for or are conducting inquiries and investigations into Hurricane Beryl and the efforts made by Houston Electric to prepare for, and respond to, this event, including the associated electric service outage issues. CenterPoint Energy and Houston Electric are also subject to current and potential future litigation and claims arising out of Hurricane Beryl. For more information regarding Hurricane Beryl-related risks, see “- Hurricane Beryl caused severe disruptions...” The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect customer satisfaction. Our ability to successfully execute our capital plan may also affect customers’, investors’, legislators’, regulators’ and creditors’ opinions and actions. Opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation. If customers, investors, legislators, regulators or creditors have or develop a negative opinion of us or our utility services, this could result in, among other things, less favorable legislative and regulatory outcomes or increased regulatory oversight, negative effects on our access to, and the cost of, capital, increased litigation and negative public perception. The foregoing may have adverse effects on our business, results of operations, cash flow and financial condition.
We are subject to operational and financial risks and liabilities arising from environmental laws and regulations, including regulation of CCR, climate change legislation and certain local initiatives that seek to limit fossil fuel usage.
Our operations are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric generating facilities and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, including among others, restricting the use of fossil fuels through future climate legislation or regulation, restricting the use of natural gas-fired appliances in new homes, limiting airborne emissions from generating facilities, restricting the way we manage wastes, including wastewater discharges, air emissions and CCR removal, and requiring remedial action or monitoring to mitigate environmental actions caused by our operations or attributable to former operations. Environmental laws and regulations applicable to our operations are complex and subject to continued uncertainty, and we are subject to risks from changing or conflicting interpretations of existing laws, modifications to existing laws, new laws, and new or modified permit terms. We may need to spend substantial amounts and devote other resources from time to time to comply with these requirements. Further, in the course of operations we have released, and may in the future inadvertently release, various contaminants. Any such releases could have a significant impact on the environment and result in significant fines. Failure to comply with applicable environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including measures taken by individuals and non-governmental organizations seeking to enforce
environmental laws against us or allege a failure to comply with such laws, and could lead to the assessment of monetary penalties, which we have been subject to from time to time, revocation of permits, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean, restore and monitor sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
Regulatory agencies have also adopted, and from time to time consider adopting, new legislation and/or modifying existing laws and regulations to reduce GHGs. There continues to be a wide-ranging policy and regulatory debate, at the state level, nationally and internationally, regarding the possible means for their regulation. The trend in environmental regulation in previous years has been to place more restrictions and limitations on activities that may impact the environment. On April 22, 2021, the United States announced new goals of 50% reduction of economy-wide GHG emissions and 100% carbon-free electricity by 2035, which formed the basis of the United States’ commitments announced in Glasgow, Scotland. These renewed climate commitments coming out of the 2021 United Nations Climate Change Conference held in Glasgow and certain executive orders resulted in the development of additional regulations and changes to existing regulations. For example, in May 2023, the EPA proposed regulations setting new GHG emission reduction targets for coal and gas-fired electric generating units that could potentially require additional operating costs or operating restrictions related to operation of Indiana Electric’s natural-gas fired units. On April 25, 2024, the EPA released its New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, Reconstructed Fossil Fuel-Fired Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule. CenterPoint Energy is currently reviewing this rule. As a distributor and transporter of natural gas and electricity, and a generator of electricity in Indiana, the Registrants’ 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 its operations or that would have the effect of reducing the consumption of natural gas or electricity or prevent the use of certain fuel types. Nevertheless, on January 20, 2025, President Trump signed an executive order to withdraw the United States from the Paris Agreement, marking a significant shift in U.S. climate policy. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. Additionally, in January 2025, President Trump signed executive orders that, among other things, direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, and call upon the EPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act and issue guidance on the “social cost of carbon” to consider whether such metric should be eliminated. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be greater than the amounts we currently anticipate, which could adversely affect our financial condition, results of operations and cash flows. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services. For further discussion, see “Business-Environmental Matters” in Item 1 and “ -Natural Gas must compete with…”
Evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels may have substantial impacts on CenterPoint Energy’s and CERC’s electric generation and natural gas businesses. For example, because Indiana Electric currently relies on coal for a portion of its generation capacity, certain financial institutions may choose not to participate in CenterPoint Energy’s financing arrangements until future coal generation closures satisfy their thresholds for investments. Further, some investors choose to not invest in CenterPoint Energy due to CenterPoint Energy’s and CERC’s use of fossil fuels. Also, certain cities in CenterPoint Energy’s and CERC’s Natural Gas operational footprint have discussed the adoption of initiatives to prohibit the construction of new natural gas facilities that would provide service and focus on electrification. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil natural gas. Certain state and local governments have also passed, or are considering, legislation banning the use of natural gas-fired appliances in new homes, which could affect consumer use of natural gas. Should such bans be enacted within Natural Gas’ operational footprint, they could adversely affect consumer demand for natural gas. Any such initiatives and legislation could adversely affect CenterPoint Energy’s and CERC’s results of operations.
Further, investors, lenders, regulators and other stakeholders are focusing on issues related to environmental justice, which may result in increased scrutiny of our applicable regulatory processes and additional costs of compliance or may adversely affect our reputation. While President Trump in January 2025 signed an executive order calling to terminate all environmental justice offices and positions in the federal government, as well as any environmental justice initiatives, programs or other activities, the focus on environmental justice matters by certain stakeholders may nevertheless provide communities opposed to our operations with greater opportunities to challenge or delay our projects. Opposition to our projects or successful challenges or appeals to permits issued for our projects could result in cancellation of such projects and the loss of investments we have made with respect thereto.
CenterPoint Energy is subject to operational and financial risks and liabilities associated with its sustainability and related activities, including the implementation of and efforts to achieve its GHG emissions reduction goals.
In September 2021, CenterPoint Energy announced its net zero emission goals for Scope 1 and certain Scope 2 emissions by 2035 and a 20-30% reduction in certain Scope 3 emissions by 2035 as compared to 2021 levels. CenterPoint Energy’s analysis and plan for execution requires it to make a number of assumptions. These goals and underlying assumptions involve risks and uncertainties and are not guarantees. Should one or more of CenterPoint Energy’s underlying assumptions require updating, its actual results and ability to achieve its net zero and GHG emissions reduction goals by 2035 could differ materially from its expectations. Certain of the assumptions that could impact CenterPoint Energy’s ability to meet its net zero and GHG emissions reduction goals and the timing thereof include, but are not limited to: GHG emission levels, service territory size and capacity needs remaining in line with Company expectations, including with respect to demand for our services and in relation to the announced sale of CenterPoint Energy’s Louisiana and Mississippi natural gas LDC businesses; the ability to appropriately estimate and effectively manage business opportunities from new customers and load growth resulting from, among other things, expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics in our service territories; regulatory approvals related to Indiana Electric’s generation transition plan and our ability to obtain such approvals; interconnection delays in the footprints of regional transmission organizations and/or interconnection costs; impacts on affordability of customer rates; customer demand for GHG emission free or lower GHG emissions energy; impacts of future regulations or legislation, including those related to the environment and tax (including changes to the renewable energy tax credits enacted in the IRA); impacts of future carbon pricing regulation or legislation, including a future carbon tax; price, availability and regulation of carbon offsets; price of fuel, such as natural gas; cost of energy generation technologies, such as wind and solar, natural gas and storage solutions; adoption of alternative energy by the public, including adoption of electric vehicles; rate of technology innovation with regards to alternative energy resources; CenterPoint Energy’s ability to implement its modernization plans for its pipelines and facilities; the ability to complete and timely implement generation alternatives, such as solar and wind generation, to Indiana Electric’s coal generation and retirement or fuel conversion dates of Indiana Electric’s coal facilities by 2035; the ability to construct and/or permit new natural gas pipelines; the ability to procure resources needed to build at a reasonable cost, the lack of or scarcity of resources and labor, any project cancellations, construction delays or overruns (including as a result of tariffs, legislation, bans, retaliatory trade measures taken against the United States or related governmental action) and the ability to appropriately estimate costs of new generation; impact of any supply chain disruptions; changes in applicable standards, metrics, methodologies or frameworks; and enhancement of energy efficiencies. Our businesses may face increased scrutiny from investors, governmental authorities and other stakeholders related to our sustainability and human capital management activities, including the goals, targets, and objectives we announce, our methodologies and timelines for pursuing them, our progress towards achieving them, and related disclosures. We could also face challenges with managing conflicting requirements and our various stakeholders’ expectations. If our sustainability practices do not align with investor or other stakeholder expectations and standards, which continue to evolve, vary, and sometimes conflict, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected. Similarly, our failure or perceived failure to pursue, fulfill or demonstrate meaningful progress towards our sustainability-focused goals, targets, and objectives, to comply with or otherwise meet ethical, environmental or other standards, regulations, or expectations, which may be varied or conflicting, or to satisfy various reporting standards with respect to these matters (including if there are real or perceived inaccuracies in the data and information we report or if we are exposed to allegations that certain public statements regarding sustainability-related matters are false and misleading “greenwashing” campaigns), within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation.
Developing and implementing plans for compliance with voluntary climate commitments can lead to additional capital, personnel and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. To the extent that we believe any of these costs are recoverable in rates, cost recovery could be resisted by our regulators and our regulators might attempt to deny or defer timely recovery of these costs. Moreover, we cannot predict the ultimate impact of achieving our emissions reduction goals, or the various implementation aspects, on our system reliability or our financial condition and results of operations.
We are subject to regulatory compliance and proceedings, which could result in higher costs for system improvements, as well as fines or other sanctions.
Houston Electric and Indiana Electric are members of ERCOT and MISO, respectively, which serve the electric transmission needs of their applicable regions. As a result of their respective participation in ERCOT and MISO, Houston Electric and Indiana Electric do not have sole operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other
utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. FERC has designated NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. FERC has approved the delegation by NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation, and for reliability in the portion of MISO that includes Indiana Electric to ReliabilityFirst Corporation, a Delaware non-profit corporation. Compliance with mandatory reliability standards may subject Houston Electric and Indiana Electric to higher operating costs and may result in increased capital expenditures, which may not be fully recoverable in rates. While Houston Electric and Indiana Electric have received minor fines in the past for noncompliance, if Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards again, they would be subject to sanctions, including potential monetary penalties, which could range as high as over a million dollars per violation per day, and non-monetary penalties, such as having to file a mitigation plan to prevent recurrence of a similar violation and having certain milestones in such plan tracked.
Additionally, compliance with existing and potential new regulations related to CERC’s operation and maintenance of natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with regulations related to CERC’s operation and maintenance of natural gas infrastructure, and we systematically monitor and renew infrastructure over time; however, CERC has received minor fines in the past for noncompliance, and a significant incident or material finding of non-compliance in the future could result in penalties and higher costs of operations.
Our businesses may be adversely affected by the intentional misconduct of our employees.
We are committed to living our core values of safety, integrity, accountability, initiative and respect and complying with all applicable laws and regulations. Despite that commitment and efforts to prevent misconduct, it is possible for employees to engage in intentional misconduct, fail to uphold our core values, and violate laws and regulations for individual gain through contract or procurement fraud, misappropriation, bribery or corruption, fraudulent related-party transactions and serious breaches of our Ethics and Compliance Code and other policies. If such intentional misconduct by employees should occur, it could result in substantial liability, higher costs, increased regulatory scrutiny and negative public perceptions, any of which could have an adverse effect on our financial condition, results of operations and cash flows. From time to time, including as part of our Ethics and Compliance program’s efforts to detect misconduct, we become aware of and expect to continue to become aware of instances of employee misconduct, which we investigate, remediate and disclose as appropriate and proportionate to the incident.
Risk Factors Affecting Financial, Economic and Market Risks
Disruptions to the global supply chain may lead to higher prices for goods and services and impact our operations, which could have an adverse impact on our ability to execute our capital plan and on our financial condition, results of operations and cash flows.
The global supply chain has experienced disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and policy instability, import tariffs and trade agreements, the COVID-19 pandemic, labor shortages, resource availability, long lead time, manufacturer production limitations, delivery delays, inflation, severe weather events and disruptions to internal or international shipping, including as a result of armed conflicts, and these disruptions have adversely impacted the utility industry. We, as well as other companies in our industry, have experienced supply chain disruptions, as well as increased prices, and we may continue to experience this in the future. For example, President Trump has expressed a desire to impose substantial new or increased tariffs and, in February 2025, imposed tariffs on several countries (the effectiveness of tariffs imposed on certain countries was subsequently delayed until March 2025) and certain imports into the United States. On February 6, 2025, the EPC contractor for Indiana Electric’s proposed natural gas combustion turbines provided a notice to Indiana Electric that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project. These tariffs, as well as any new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could increase or cause volatility in the cost of and negatively impact our ability to procure materials, supplies (such as natural gas) or services necessary for our business and capital plan, lead to a scarcity of resources and labor necessary for our business and capital plan, further extend lead time or otherwise negatively impact the supply chain. Examples of materials necessary for the transmission and distribution of power we and our industry have experienced difficulties in procuring include transformers, wires, cables, meters, poles and solar panels. If the supply chain disruption persists or worsens, we may experience difficulties in procuring these resources and others necessary to operate our businesses in the future. As a result, we may not be able to procure the resources, including labor, needed to timely perform storm restoration activities, fully execute on our ten-year capital plan and/
or achieve our net zero emission and GHG emissions reduction goals. Moreover, inflation and high interest rates have contributed to increased prices for materials and services experienced by us and other companies in our industry and, if such conditions continue, they may have adverse effects on our business, results of operations, cash flow and financial condition. Even if we are able to procure the necessary resources, we might not be able to do so at a reasonable cost or in a timely manner which could result in project cancellations or scope changes, delays, cost overruns and under-recovery of costs. If we are unable to fully execute on capital plans, our financial condition, results of operations and cash flows may be adversely affected.
If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures or refinance outstanding indebtedness could be limited.
Our businesses are capital intensive, and we rely on various sources to finance our capital expenditures. For example, we depend on (i) long-term debt, (ii) borrowings through our revolving credit facilities and, for CenterPoint Energy and CERC, commercial paper programs and (iii) if market conditions permit, issuances of additional shares of common stock or shares of preferred stock by CenterPoint Energy. We may also use such sources to refinance any outstanding indebtedness as it matures. Additionally, from time to time, our operating subsidiaries, including Houston Electric and CERC, may rely on intercompany borrowings from CenterPoint Energy that may be sourced from CenterPoint Energy’s external financings. As of December 31, 2024, CenterPoint Energy had $21 billion of outstanding indebtedness on a consolidated basis, which included $324 million of non-recourse Securitization Bonds. For information on outstanding indebtedness of CenterPoint Energy, Houston Electric and CERC as well as future maturities, see Note 12 to the consolidated financial statements. If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures, including our ten-year capital plan (which has increased to nearly $47.5 billion through 2030), or refinance our outstanding indebtedness could be limited. Our future financing activities may be significantly affected by, among other things:
•general economic and capital market conditions, including inflation;
•credit availability from financial institutions and other lenders;
•investor confidence in us and the markets in which we operate;
•the future performance of our businesses;
•maintenance of acceptable credit ratings;
•actions from the Federal Reserve, including changes in interest rates and unanticipated actions;
•market expectations regarding our future earnings and cash flows;
•investor willingness to invest in companies associated with fossil fuels;
•our ability to access capital markets on reasonable terms;
•timing of future securitizations by jurisdictions in which we operate; and
•provisions of relevant securities laws.
The Registrants’ current credit ratings and any changes in credit ratings in 2024 and to date in 2025 are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Other Matters - Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of Part II of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be reduced or withdrawn by a rating agency. The Registrants note these credit ratings are not recommendations to buy, sell or hold their securities. 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 an adverse impact on their ability to access capital on acceptable terms. For example, if CERC’s credit rating were to decline, it may have an adverse impact on the cost of borrowings and, in extraordinary market conditions, it may limit the ability to access the debt capital markets. Additionally, CERC might be required to post collateral under its shipping arrangements or to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s financial condition, results of operations and cash flows could be adversely affected.
CenterPoint Energy is a holding company that derives all of its operating income from, and holds substantially all of its assets through, its subsidiaries. As a result, CenterPoint Energy depends on the performance of and distributions from its subsidiaries to meet its payment obligations and to pay dividends on its common stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.
CenterPoint Energy derives all of its operating income from, and holds substantially all of its assets through, its subsidiaries. Similarly, as a result of the Restructuring, CERC derives a significant portion of its operating income from and holds a significant portion of its assets through its subsidiaries, including Indiana Gas and CEOH. As a result, CenterPoint Energy, and to a lesser extent, CERC, depend on the performance of and distributions from their respective subsidiaries to meet their respective payment obligations and to pay dividends on their respective common stock. In general, CenterPoint Energy’s and CERC’s subsidiaries are separate and distinct legal entities and have no obligation to provide them with funds for their
respective payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit CenterPoint Energy’s and CERC’s respective subsidiaries’ ability to make payments or other distributions to CenterPoint Energy or CERC, and their respective subsidiaries could agree to contractual restrictions on their ability to make payments or other distributions. Further, as part of the agreement resulting from Houston Electric’s 2019 base rate case, Houston Electric filed a base rate proceeding in 2024. Further ring-fencing measures could be imposed on Houston Electric in the future through legislation or PUCT rules or orders. While current ring-fencing measures have not impacted Houston Electric’s ability to pay dividends to CenterPoint Energy, the imposition of any additional measures impacting CenterPoint Energy’s ability to receive dividends from Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations. Any such adverse effect on CenterPoint Energy could also adversely affect Houston Electric’s and/or CERC’s cash flows, credit quality, financial condition and results of operations as CenterPoint Energy may not be able to financially support Houston Electric and/or CERC if and when necessary.
CenterPoint Energy’s right to receive assets of any subsidiary, and therefore the right of its creditors to participate in those assets, are structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if CenterPoint Energy were a creditor of any subsidiary, its rights as a creditor would likely be effectively subordinated to any security interest in the assets of that subsidiary and any senior indebtedness of the subsidiary.
CenterPoint Energy’s previously owned Energy Systems Group business has performance and warranty obligations, some of which are guaranteed by CenterPoint Energy.
On June 30, 2023, CenterPoint Energy closed the sale of its Energy Systems Group business. Prior to June 30, 2023 and as part of the normal course of its business, Energy Systems Group issued performance bonds and other forms of assurance that committed it to operate facilities, pay vendors or subcontractors and support warranty obligations. As the parent company prior to the closing of the sale, CenterPoint Energy or Vectren guaranteed certain of its subsidiaries’ commitments. When Energy Systems Group was wholly owned by CenterPoint Energy, these guarantees did not represent incremental consolidated obligations, but rather, these guarantees represented guarantees of Energy Systems Group’s obligations to allow it to conduct business without posting other forms of assurance. Neither CenterPoint Energy nor Vectren has been called upon to satisfy any obligations pursuant to these parental guarantees to date but may be required to do so in the future. For further information, see Note 14(c) to the consolidated financial statements.
An impairment of goodwill, long-lived assets or equity method investments or a fair value adjustment could reduce our earnings.
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill is tested for impairment at least annually, as well as when events or changes in circumstances indicates the carrying value may not be recoverable. While CenterPoint Energy has identified and recorded goodwill impairments in the past, no impairments to goodwill were recorded during the years ended December 31, 2024, 2023, and 2022. See Note 6 to the consolidated financial statements for further information. Should the annual goodwill impairment test or another periodic impairment test or an observable transaction indicate the fair value of our assets is less than the carrying value, we would be required to take a non-cash charge to earnings with a correlative effect on equity, increasing balance sheet leverage as measured by debt to total capitalization. A non-cash impairment charge or fair value adjustment could adversely impact our financial condition and results of operations.
If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments would result in significant cash payments, which would adversely impact its cash flows and liquidity. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows and liquidity.
CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2024. 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. CenterPoint Energy may redeem all of the ZENS at any time at a redemption amount per ZENS equal to the higher of the contingent principal amount per ZENS $9 million in the aggregate, or $0.62 per ZENS, as of December 31, 2024, or the sum of the current market value of the reference shares attributable to one ZENS at the time of redemption. In the event CenterPoint Energy redeems the ZENS, in addition to the redemption amount, it would be required to pay deferred taxes related to the ZENS. CenterPoint Energy’s ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2024, deferred taxes of approximately $802 million would have been payable in 2024, based on 2024 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2024 to fund the aggregate
redemption amount, capital gains taxes of approximately $84 million would have been payable in 2024. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows and liquidity. This could happen if CenterPoint Energy’s creditworthiness were to drop, the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of ZENS-Related Securities CenterPoint Energy owns or from other sources, ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and ZENS-Related Securities shares would typically be disposed when ZENS are exchanged and ZENS-Related Securities shares are sold.
Our potential business strategies and strategic initiatives, including merger and acquisition activities and the disposition of assets or businesses, may not be completed or perform as expected, adversely affecting our financial condition, results of operations and cash flows.
Our financial condition, results of operations and cash flows depend, in part, on our management’s ability to implement our business strategies successfully and realize the anticipated benefits therefrom. In 2021, we announced our strategic goals for CenterPoint Energy, including our ten-year capital plan, and net zero and GHG emissions reduction goals. Our strategic goals are subject to the risks described in this section and various assumptions. These assumptions may require updating or we may not be able to execute on these strategic goals in a timely manner or at all. If we are unable to execute on our strategic goals, including our ten-year capital plan, the benefits therefrom may not be fully realized, if at all, and our reputation may be adversely affected.
From time to time we have made, and may continue to make, acquisitions or divestitures of, or other similar transactions involving, businesses and assets, such as our announced sale of our Louisiana and Mississippi natural gas LDC businesses, Houston Electric’s proposed release of its 15 large 27 MW to 32 MW TEEEF units to the San Antonio area and other potential future subleasing of TEEEF and our completed sale of our Energy Systems Group business, form joint ventures or undertake restructurings, such as the Restructuring. However, suitable acquisition candidates or potential buyers may not continue to be available on terms and conditions we find acceptable, or the expected benefits of completed acquisitions, dispositions or similar transactions may not be realized fully or at all or may not be realized in the anticipated timeframe. If we are unable to make acquisitions, or if those acquisitions do not perform as anticipated, our future growth may be adversely affected. Further, any completed or future acquisitions, dispositions or similar transactions involve substantial risks, including the following:
•acquired businesses or assets, or other business strategies and strategic initiatives may not produce revenues, earnings or cash flow at anticipated levels;
•acquired businesses or assets, or other business strategies and strategic initiatives could have environmental, permitting or other problems for which contractual protections prove inadequate;
•we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;
•we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
•acquisitions, dispositions or similar transactions, or the pursuit of such transactions, including any separation or disentanglement efforts or requirements, such as the provision of transition services, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures; and
•we may not receive regulatory approvals necessary to complete an acquisition, disposition or similar transaction in a timely manner or at all.
On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 4 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or otherwise not consummated.
Changing demographics, poor investment performance of pension plan assets and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our financial condition, results of operations and liquidity.
CenterPoint Energy and its subsidiaries maintain qualified defined benefit pension plans covering certain of its employees. Costs associated with these plans are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, contributions to the plan, the number of plan participants and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and CenterPoint Energy may be required to make unplanned contributions in the event of a decline in the market
value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations, or government regulations that increase minimum funding requirements or the pension liability. In 2023 and 2022, CenterPoint Energy had a settlement expense for its pension plans as a result of an increase in eligible employee retirements and pension plan distributions. See Note 8 to the consolidated financial statements for further information. In addition to affecting CenterPoint Energy’s funding requirements, these factors could adversely affect our financial condition, results of operations and liquidity.
We may be significantly affected by changes in federal income tax laws and regulations, including any comprehensive federal tax reform legislation.
Our businesses are impacted by U.S. federal income tax policy. The TCJA, CARES Act, and the IRA significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by among other things, reducing the federal corporate income tax rate, limiting interest deductions, altering the expensing of capital expenditures, enacting a new CAMT, and expanding federal tax credits for cleaner energy production. Based on guidance available as of December 31, 2024, the Registrants will be subject to the CAMT included in the IRA.
The interpretive guidance issued by the IRS and state tax authorities may be inconsistent with our interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. In addition, while certain regulators have allowed the Registrants to recover certain costs associated with the CAMT in the past, the retail regulatory treatment of the expanded tax credits and CAMT could impact the Registrants’ future cash flows, and this legislation could result in unintended consequences not yet identified that could have an adverse impact on the Registrants’ financial results and future cash flows.
Further federal tax reform legislation, including legislation proposed by the new presidential administration, could be enacted that may significantly change the federal income tax laws applicable to domestic businesses, including changes that may impact investment incentives and deductions for depreciation and interest, among other deductions. While the details of the Trump Administration’s potential tax reform have not been announced as of the date of the filing of this Form 10-K, during his 2024 presidential campaign, President Trump outlined several intended reforms, including reducing the corporate tax rate for domestic oil and gas production, repealing or revising the IRA, extending certain provisions of the TCJA and imposing new tariffs. In January 2025, President Trump signed an executive order that, among other things, pauses the disbursement of funds appropriated through the IRA. In February 2025, President Trump imposed tariffs on various countries (the effectiveness of tariffs imposed on certain countries was subsequently delayed until March 2025) and certain imports into the United States. New federal tax reform legislation and the implementation of new or increased tariffs could lead to increases in market interest rates, a decrease in U.S. economic growth, and/or recession. Additionally, the change in administration and the expiring tax cuts in the TCJA could result in the repeal of or changes to the IRA, including renewable energy tax credits enacted in the IRA, and these changes could impact CenterPoint Energy’s net zero and GHG emissions reduction goals. While CenterPoint Energy and its subsidiaries cannot assess the overall impact of any such potential legislation or other actions on our businesses, it is possible that our financial condition, results of operations or cash flows could be negatively impacted. Furthermore, with any enacted federal tax reform legislation, it is uncertain how state commissions and local municipalities may require us to respond to the effects of such tax legislation, including determining the treatment of EDIT and other increases and decreases in our revenue requirements. As such, potential regulatory actions in response to any enacted tax legislation could adversely affect our financial condition, results of operations and cash flows.
Risk Factors Affecting Safety and Security Risks
The Registrants’ businesses have safety risks.
The Registrants’ facilities and distribution and transmission systems have been and may in the future be involved in incidents that result in injury, death, or property loss to employees, customers, third parties (including vendors, suppliers and contractors), or the public. Although the Registrants have insurance coverage for many potential incidents, depending upon the nature and severity of any incident, they could experience financial loss, claims and litigation, damage to their reputation, and negative consequences from regulatory authorities or other public authorities. Further, certain CenterPoint Energy employees who work in the field have experienced threats of violence during the performance of their work. Threats of violence, actual violence and other concerns may result in employees and third parties supporting the work of the Registrants being unable or unwilling to complete critical functions, which could adversely affect our businesses, financial condition and results of operations, and could make it harder to, among other things, recruit and retain certain employees.
Cyberattacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our reputation, financial condition, results of operations and cash flows.
We are subject to cyber and physical security risks related to our information technology systems, operational technology, network infrastructure, and other technology and facilities used to conduct almost all of our businesses. The operation of our electric generation, transmission and distribution systems is dependent on the physical interconnection of our facilities, as well as communications among the various components of our systems and third-party systems. Further, certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a cyberattack or unauthorized access in any one of these systems could potentially impact the other systems. Similarly, our business operations, including our transmission systems and natural gas pipelines, are part of an interconnected system. Disruption of those systems, or our ability to communicate with those systems, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by man-made events, such as cyberattacks or acts of terrorism, may disrupt our ability to conduct operations and control assets and negatively impact our business.
The sophistication of cybersecurity threats, including those leveraging AI, continues to increase, and the controls and preventative actions we take to reduce the risk of cybersecurity incidents and protect our systems, including the regular testing of our cybersecurity incident response plan, may be insufficient. In addition, new technology that could result in greater operational efficiency, such as our use of AI, may further expose our computer systems to the risk of cybersecurity incidents. Cyberattacks, including phishing attacks and threats from the use of malware, ransomware and viruses or malicious code, and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect reputation, impact our customers, increase costs and subject us to possible legal claims and liability. While we have implemented and maintain a cybersecurity program designed to protect our information technology, operational technology, and data systems from such attacks, our cybersecurity program does not prevent all breaches or cyberattack incidents. Publicly known vulnerabilities in our information technology and operational technology environments may not be remediated before an adversary could discover or exploit them. Attackers can also exploit new, unknown vulnerabilities (e.g., zero-day vulnerabilities) and vulnerabilities where a patch or other remediation measure is not yet available. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. We have also experienced, and expect to continue to experience, cyber intrusions and attacks to our information systems and those of third parties, including vendors, suppliers, contractors and quasi government entities who perform certain services for us or administer and maintain our sensitive information. These prior intrusions and attacks have not had a material impact on our business, results of operations, or financial condition. Because technology is increasingly complex and cyberattacks are increasingly sophisticated and more frequent, there is a risk such incidents could have an adverse effect on us in the future. The risk of a disruption or breach of our operational technology systems, or the compromise of the data processed in connection with our operations, through a cybersecurity breach or ransomware attack, has increased as attempted attacks have advanced in sophistication and number around the world. Our insurance coverage may not be sufficient to cover all costs associated with cybersecurity threats or incidents.
Our continued efforts to integrate, consolidate and streamline our operations have also resulted in increased reliance on current and recently completed projects for technology systems. A failure to maintain and enhance existing information technology systems could adversely affect our operations. Procedures we implement to protect our systems may be insufficient to protect and safeguard against unauthorized access to secured data. A failure of our technologies or procedures, or our inability to support and integrate these technologies across our subsidiaries, could materially and adversely impact our operations, diminish customer confidence and our reputation, materially increase the costs we incur to protect against these risks and subject us to possible financial liability or increased regulation or litigation.
We depend on the secure operations of our physical assets to transport the energy we deliver and our information technology to process, transmit and store electronic information, including information and operational technology we use to safely operate our energy transportation systems. Security breaches, attacks on our infrastructure and facilities, including against the Registrants or as a means to harm a third-party by disrupting the transmission and distribution of energy, or acts of terrorism, including by foreign or domestic actors, could expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect our operations, as well as potential data privacy breaches and loss of protected personal information and other sensitive information, such as Critical Energy Infrastructure Information. Such losses could result in operational impacts, damage to our assets, public or personal safety incidents, impacts to our customers, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions, litigation and a potential adverse effect on our operations, financial condition, results of operations and cash flows. There is no certainty that costs incurred related to actual or thwarted cyberattacks, or for the safeguarding against such security threats, will be recoverable through rates.
Compliance with and changes in cybersecurity laws and regulations have a cost and operational impact on our business, and failure to comply with such requirements could adversely impact our reputation, financial condition, results of operations and cash flows.
Cyberattacks are becoming more sophisticated, and U.S. government warnings have indicated infrastructure assets, including pipelines and electric generation and infrastructure, may be specifically targeted by certain groups. Regulators have adopted numerous rules and regulations regarding cybersecurity. As a result, CenterPoint Energy continues to take measures to comply with the TSA pipeline security directive requirements applicable to critical pipeline owners and operators. These security directives require CenterPoint Energy to establish, implement and assess a TSA-approved Cybersecurity Implementation Plan that describes the security measures maintained to comply with relevant provisions of the security directives. CenterPoint Energy is also subject to standards enacted by NERC and enforced by FERC regarding protection of critical infrastructure assets required for operating North America's bulk electric system. We may be required to expend significant additional resources and costs to respond to cyberattacks, to continue to modify or enhance our protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. There is no certainty that such costs incurred will be recovered through rates. We also face increasing and evolving disclosure and reporting obligations related to cybersecurity events, and there is no certainty that we will be able to meet existing or future disclosure obligations and avoid the risk of potentially having our disclosures misinterpreted when made. National security or public safety considerations may further affect, or in some instances prevent, our public disclosure of a cybersecurity incident in certain circumstances. Any failure to remain in compliance with these government regulations or failure in our cybersecurity protective measures may result in enforcement actions which may have an adverse effect on our reputation, financial condition, results of operations and cash flows.
Failure to maintain the security of personal information could adversely affect us.
In connection with our businesses, we and our third parties (vendors, suppliers, and contractors) collect and retain personal information (for example, information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties will adequately protect that information. The regulatory environment surrounding information security and data privacy continues to evolve and is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant costs, fines and penalties and liabilities for us. The systems we have implemented to protect our information technology, operational technology, and data systems from attacks cannot prevent all security breaches, and the systems we have implemented to manage and protect personal information cannot prevent all privacy breaches. We and some of our third parties that maintain personal information have experienced, and expect to continue to experience, data privacy incidents and breaches; however, to date, we have not experienced a material data privacy incident or breach. A significant theft, loss or fraudulent use of the personal information we maintain, or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions and other legal requirements, could adversely impact our reputation and could result in significant costs, fines and penalties and liabilities for us. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection privacy, we may incur significant liabilities and penalties as a result.
We may not be successful in our adoption, development and deployment of AI, which could adversely affect our business, reputation, or financial results.
We are using and exploring the further use of AI, including generative AI, and its ability to enhance the services we offer to the communities we serve. There are significant risks involved in developing and deploying AI, and ineffective or inadequate development or deployment of AI practices by us or our third-parties (vendors, suppliers, and contractors) could result in unintended consequences. We contract with third-parties that use AI in products and services they provide and we may not have full control or visibility over the quality, performance, security or compliance of the products and services that incorporate AI-related technology. Additionally, the use of AI may not enhance our services or be beneficial to our business, including with respect to the efficiency and resiliency of our systems. For example, our AI-related efforts may give rise to risks related to harmful content, accuracy, bias, discrimination, intellectual property infringement or misappropriation, defamation, data privacy, and cybersecurity, among others. In addition, the adoption of AI may subject us to new or enhanced governmental or regulatory scrutiny, new or amended laws, rules, directives, and regulations governing the use of AI, litigation, ethical concerns, negative consumer perceptions as to automation and AI, or other complications that could adversely affect our business, reputation, or financial results. We may not be able to recover our investments in AI technology through our regulatory proceedings, and our use of, or our third parties’ use of, AI may subject us to legal liability. Similarly, as AI continues to evolve, we may not be able to adopt and implement AI as quickly as our customers or communities desire or regulators may require, which could also adversely affect us. AI is a relatively new and rapidly evolving technology, and we are unable to predict all of the risks that may result from the adoption of our AI initiatives.
General and Other Risks
Our revenues and results of operations are seasonal.
Houston Electric’s, Indiana Electric’s and Natural Gas’ revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity and natural gas usage, as applicable. Houston Electric’s revenues are generally higher during the warmer months. As in certain past years, unusually mild weather in the warmer months could diminish Houston Electric’s results of operations and harm its financial condition. Conversely, as in certain past years, extreme warm weather conditions could increase Houston Electric’s results of operations in a manner that would not likely be annually recurring. A significant portion of Indiana Electric’s sales are for space heating and cooling. Consequently, as in certain past years, Indiana Electric’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather, while, as has occurred in certain past years, more extreme seasonal weather conditions could increase Indiana Electric’s results of operations in a manner that would not likely be annually recurring. Natural Gas’ revenues are customarily higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish Natural Gas’ results of operations and harm its financial condition. Conversely, as occurred in certain past years, extreme cold weather conditions could increase its results of operations in a manner that would not likely be annually recurring. For additional risks related to the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements for further information.
Climate change and other weather and natural disaster impacts could adversely impact financial results from our businesses and our results of operations.
A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territories and our business. If climate changes occur that result in warmer temperatures than normal in our service territories, financial results from our businesses could be adversely impacted. For example, where natural gas is used to heat homes and businesses, warmer weather might result in less natural gas being used, adversely affecting us.
Another possible result of climate change is more frequent and more severe weather events. Weather-related incidents have become more prevalent, unpredictable and severe as a result of climate change or other factors. Severe weather events impact our service territories, primarily when hurricanes, tornadoes, floods, severe winter weather conditions, including ice storms, wildfires, thunderstorms, high winds, hail, derecho events, microbursts, or extreme temperatures (high heating/cooling days) occur, which can impact our operations and our ability to serve our customers, including resulting in large-scale and/or prolonged outages. To the extent the frequency and severity of extreme weather events increases, our costs of providing service may increase, including the costs and availability of procuring insurance related to such impacts, and those costs may not be recoverable. Further, events of extreme weather could make it unsafe or hinder the effectiveness of our employees to fix, maintain and restore power to affected areas and could harm our reputation. Since certain of our facilities are located along or near the Texas Gulf Coast, increased or more severe hurricanes, tornadoes or derecho events could increase our costs to repair damaged facilities and restore service to our customers. Our Electric and Natural Gas operations in our service territories have both been impacted by severe weather events, including the February 2021 Winter Storm Event, the May 2024 Storm Event and Hurricane Beryl, and could experience similar events in the future, which could have an adverse impact on our financial condition, results of operations and cash flows.
Wildfires also have the potential to negatively affect communities our service territories and the surrounding areas, as well as our electric and natural gas infrastructure, including Houston Electric’s and Indiana Electric’s vast network of electric transmission and distribution lines and facilities and CERC’s natural gas distribution systems. The possibility of wildfires and the risk of damage to our network, facilities and systems resulting therefrom may be exacerbated by severe weather events and the effects of climate change. The continued expansion of the wildland-urban interface has also increased wildfire risk to communities in our service territories. While we proactively take steps to mitigate wildfire risk in the areas of our electrical and natural gas assets, wildfire risk is always present. We could be held liable for damages incurred as a result of wildfires or incur reputational harm if it was determined that they were caused by or enhanced due to any fault of CenterPoint Energy. In addition, while we maintain wildfire insurance, our insurance may not be sufficient to cover all losses we may incur as a result of wildfires. Wildfires could also lead to significant financial distress and further increased costs for wildfire insurance or lack of availability thereof. Insufficient wildfire insurance coverage, increased wildfire insurance costs and a lack of wildfire insurance availability could adversely impact our financial condition, results of operations and cash flows. Furthermore, any
damage caused to our assets, loss of service to our customers or liability imposed as a result of wildfires could negatively impact our financial condition, results of operations and cash flows.
In the long term, climate change could also cause shifts in population, including customers moving away from our service territories. When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results are impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs or recover in a timely manner, or if recovery of such costs results in higher rates and reduced demand for our services, our future financial results may be adversely impacted. Similarly, public and private efforts to address climate change, such as by legislation, regulation, actions by private interest groups, and litigation, could impact our ability to continue operating our businesses as we do today, significant aspects of which rely on fossil fuels. These initiatives could have a significant impact on us and our operations as well as on our third-party suppliers, vendors and partners, which could impact us by among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to us. For further information on these initiatives, see “- We are subject to operational…” Finally, we may be subject to climate change litigation, which could result in substantial fines, penalties or damages and restrictions on our operations. The utility industry has already faced such litigation, challenging its marketing and use of fossil fuels and attributing climate change to emissions resulting from the use of fossil fuels. For more information, see “- CenterPoint Energy is subject to operational and financial risks...”
We are exposed to risks related to changes in demand and energy consumption that could adversely impact financial results from our businesses and our results of operations.
Our businesses are affected by reduction in energy consumption due to factors including economic, climate and market conditions in our service territories, energy efficiency initiatives, use of alternative technologies and changes in our customers’ perceptions regarding natural gas usage as a result of incidents of other utilities involving natural gas pipelines, which could impact our ability to grow our customer base and our rate of growth. Growth in customer accounts and growth of customer usage each directly influence demand for electricity and natural gas and the need for additional delivery facilities. Customer growth and customer usage are affected by a number of factors outside our control, such as mandated energy efficiency measures, bans on or further regulation of natural gas-fired appliances, demand-side management goals, distributed generation resources and economic and demographic conditions, including population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. Declines in demand for electricity and natural gas in our service territories due to pipeline incidents of other utilities, increased electricity and natural gas prices as experienced during the February 2021 Winter Storm Event and during periods of persisting high inflation or economic downturns, among other factors, could reduce overall usage and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity and natural gas. Although Houston Electric’s and Indiana Electric’s transmission and distribution businesses are subject to regulated allowable rates of return and recovery of certain costs under periodic adjustment clauses, overall declines in electricity delivered and used as a result of economic downturn or recession could reduce revenues and cash flows, thereby diminishing results of operations. A reduction in the rate of economic, employment and/or population growth could result in lower growth and reduced demand for and usage of electricity and natural gas in such service territories. Additionally, certain laws in our service territories allow municipalities to create, own, and operate utilities. If one or more municipalities in our service territories create new or supplemental utilities, or impair the franchises under which we serve customers in the applicable municipalities, it could result in lower growth and reduced demand for and usage of electricity and natural gas in such service territories. Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or natural gas or number of customers and may result in our failure to fully realize anticipated benefits from significant capital investments and expenditures, which could have an adverse effect on our financial condition, results of operations and cash flows.
Additionally, our operations are affected by new customers and load growth. For example, the expansion of data centers (associated with, among other things, increasing demand for artificial intelligence), energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, among others, could lead to an unprecedented increase in demand for electric power in our service territories. As we evaluate business opportunities presented by such development in our service territories, we are subject to potential challenges including accurately predicting future power needs due to rapidly changing technology and market dynamics, managing the potential power demand, generation sources, and transmission capabilities to meet potential load growth, financing the capital investment needed to build and maintain the necessary infrastructure to support such development, managing the possible environmental impact of the potential increased power demand, achieving our net zero and GHG emissions reduction goals and evaluating and complying with evolving regulations related to such development. Our efforts to predict and address these challenges could have a material impact on us, including if we fail to fully realize anticipated benefits from significant capital investments and expenditures made to address such development, which could have an adverse effect on our financial condition, results of operations and cash flows.
Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results.
We have risks associated with aging infrastructure assets, including the failure of equipment or processes and potential breakdowns due to such aging. The age of certain of our assets may result in a need for replacement or higher level of maintenance costs because of our risk based federal and state compliant integrity management programs. As part of our long-term capital plan, GHRI and the SRP, we continue to make upgrades to our aging infrastructure assets to enhance the reliability of our infrastructure. Failure to achieve timely and full recovery of expenses associated with our aging infrastructure could adversely impact revenues and could result in increased capital expenditures or expenses. In addition, the nature of information available on aging infrastructure assets may make inspections, maintenance, upgrading and replacement of the assets particularly challenging. Also, our ability to successfully maintain or replace our aging infrastructure may be delayed or be at a greater cost than anticipated due to supply chain disruptions. Further, with respect to Natural Gas’ operations, if certain pipeline replacements (for example, cast-iron or bare steel pipe) are not completed timely or successfully, government agencies and private parties might allege the uncompleted replacements caused events such as fires, explosions or leaks. Although we maintain insurance for certain of our facilities, our insurance coverage may not be sufficient in the event a catastrophic loss is alleged to have been caused by a failure to timely complete equipment replacements. Insufficient insurance coverage and increased insurance costs could adversely impact our financial condition, results of operations and cash flows. Finally, aging infrastructure may complicate our utility operations ability to address climate change concerns and efforts to enhance resiliency and reliability. See “- Disruptions to the global supply...”
Our financial condition, results of operations and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.
Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks inherent in the generation, transmission and distribution of electricity and in the delivery of natural gas that could result in substantial losses or other damages. From time to time, we have and may in the future experience various risks associated with the operations of our facilities, including, but not limited to, the following:
•operator error or failure of equipment or processes, including natural gas ignition events or associated incidents, pipeline over-pressure events or ruptures, or failure to follow appropriate safety protocols for, among others, the transmission and distribution of electricity and in the delivery of natural gas, including operations of our peak shaving facilities;
•the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;
•operating limitations that may be imposed by environmental or other regulatory requirements;
•labor disputes;
•information technology or financial and billing system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;
•compliance mandates that result in penalties from our regulators;
•failure to obtain in a timely manner and at reasonable prices the necessary fuel, such as coal and natural gas, building materials or other items needed to operate our facilities;
•information technology failure, including failure of AI technology, that affects our ability to access customer information or causes us to lose confidential or proprietary data that adversely affects our reputation or exposes us to legal claims; and
•catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornados, derecho events, ice storms, terrorism, wildfires, pandemic health events, geopolitical conflict or other similar occurrences, including any environmental impacts related thereto, which catastrophic events may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts, and for which our emergency preparedness plans may not be adequate or we may not respond effectively, which could result in public or employee harm.
Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities, delays in cash collections, harm to our reputation, less favorable legislative and regulatory outcomes or increased regulatory oversight, any of which could have an adverse effect on our business, financial condition, results of operations and
cash flows. Such events have and may in the future result in the imposition of regulatory or environmental fines and increased litigation.
Our businesses will continue to have to adapt to technological change and may not be successful or may have to incur significant expenditures to adapt to technological change.
We operate businesses that require sophisticated data collection, processing systems, software and other technology. Some of the technologies supporting the industries we serve are changing rapidly and increasing in complexity. New technologies will emerge or grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant investments and expenditures so that we can continue to provide cost-effective and reliable methods for energy production and delivery. Among such technological advances are distributed generation resources (e.g., private solar, microturbines, fuel cells), energy storage devices and more energy-efficient buildings and products designed to reduce energy consumption, emissions attributable to our operations and waste. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, such as under the IRA, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services, including Indiana Electric’s generating facilities becoming less competitive and economical. Further, certain regulatory and legislative bodies have introduced or are considering requirements and incentives to reduce energy consumption by certain dates. Just as high inflation and rising interest rates incentivize our customers to consume less energy, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric and natural gas devices or other improvements in or applications of technology could lead to declines in per capita energy consumption.
Our future success will depend, in part, on our ability to anticipate and adapt to these technological changes in a cost-effective manner, to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards, and to recover all, or a significant portion of, any unrecovered investment in obsolete assets. For example, an expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, among others, could generate a significant increase in demand for electric power in CenterPoint Energy’s service territories, which may require us to rapidly adopt new technologies and make significant transmission and distribution investments, including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. If we fail to adapt successfully to any technological change or obsolescence, fail to obtain access to important technologies or incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, our businesses, financial condition, results of operations and cash flows could be adversely affected.
Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our financial condition, results of operations and cash flows.
We currently have insurance in place, such as general liability and property insurance, to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage premiums continue to increase, and insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to fully cover or restore the loss or damage without negative impact on our financial condition, results of operations and cash flows. Costs, damages and other liabilities related to recent events and incidents that affected other utilities, such as wildfires, winter storms and explosions, among other things, have exceeded or could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the marketplace for insurance coverage to utility companies may be unavailable or limited in capacity or any such available coverage may be deemed by us to be cost prohibitive under current conditions. Insurance premiums for any such coverage, if available, may not be eligible for recovery, whether in full or in part, by us through the rates charged by our utility businesses.
In common with other companies in its line of business that serve coastal regions, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and insurance capacity to be limited. Historically, Houston Electric has been able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise. In the future, any such recovery may not be granted. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its financial condition, results of operations and cash flows.
Global or regional health pandemics, epidemics or similar public health threats could negatively impact our business, outlook, financial condition, results of operations and liquidity.
Current and future health pandemics, epidemics and similar public health threats and the measures implemented to contain their spread, such as travel bans and restrictions, quarantines and vaccination mandates, have had and may in the future have widespread impacts on the global economy, our employees, customers, and third-party business partners. The severity, magnitude and duration of future health threats is uncertain and hard to predict. Any future health threat could impact our business in numerous ways, including, but not limited to, those outlined below:
•reduced demand from our commercial and industrial customers and shifts in demand for our services;
•delayed service to customers because of shutdowns or illness and travel restrictions among our employees;
•negative impacts to the financial condition of our customers and REPs and their ability to pay for our services, and our ability to disconnect service for non-payment may be limited, and state regulators may impose bill deferral programs;
•potential limits or significant or entire curtailments of the ability of public utility commissions to approve or authorize applications and other requests we may make with respect to our businesses, including delaying rate making proceedings;
•increased risk to our cybersecurity program as a result of an increase in cyberattacks during the pandemic and increased remote working arrangements (for further information, see “- Risk Factors Affecting Safety and Security Risks”);
•increased rates of inflation and delays in our supply chain and our ability to complete maintenance, repairs, and capital programs, which could result in disruption, increased costs and our inability to execute on or require us to make modifications to our capital plan; and
•accelerated employee turnover as a result of concerns regarding restrictions and guidelines, including mask mandates and quarantine mandates, and increased acceptability of alternative work arrangements.
Like many companies, we experienced the above and other impacts during the COVID-19 pandemic. These and other impacts of global or regional health pandemics, epidemics or similar public health threats could also have the effect of heightening many of the other risks described in this section and the other reports we file from time to time with the SEC. We might not be able to predict or respond to all impacts on a timely basis to prevent near- or long-term adverse impacts to our operations, financial condition and liquidity. The ultimate impact of public health threats on our business depends on factors beyond our knowledge or control, including the duration and severity of the outbreak as well as third-party actions taken to contain the spread and mitigate the public health effects. Any of these factors could have a negative impact on our business, outlook, financial condition and results of operations, which impact could be material.
Our success depends upon our ability to attract, effectively transition, motivate and retain key employees and identify and develop talent to succeed senior management.
We depend on senior executive officers and other key personnel. Our success depends on our ability to attract, effectively transition and retain key personnel. Further tightening of the labor market and increasing wages to attract and retain key personnel may adversely affect our ability to attract and retain key personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part on our ability to identify, motivate and develop talent to succeed senior management. The retention of key personnel and appropriate senior management succession planning will continue to be critically important to the successful implementation of our strategies.
Failure to attract and retain an appropriately qualified workforce and maintain good labor relations could adversely impact the operations of our facilities and our results of operations.
Our businesses are dependent on recruiting, retaining and motivating employees. Like many companies in the utilities industry and other industries, we have experienced higher than normal turnover of employees as a result of a number of factors, including a tightening labor market, increasing remote working opportunities, employees shifting industries, individuals deciding not to work and a maturing workforce. Of our employee population, not including employees of Energy Systems Group prior to its divestiture on June 30, 2023 or temporary employees, 18.2%, 18.7%, and 19.3% were retirement eligible as of December 31, 2024, 2023, and 2022, respectively. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, increased turnover or the unavailability of contract resources, may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our
businesses, particularly the specialized skills and knowledge required to construct and operate generation facilities, a technology-enabled power grid and transmission and distribution infrastructure, among other facilities. If we are unable to successfully attract and retain an appropriately qualified workforce, our ability to execute on our 10-year capital plan and our results of operations could be negatively affected.
Furthermore, the operations of our facilities depend on good labor relations with our employees, and several of our businesses have in place collective bargaining agreements with different labor unions, comprising approximately 39% of our workforce. We have several separate bargaining units, each with a unique collective bargaining agreement described further in Note 8(j) to the consolidated financial statements, which information is incorporated herein by reference. The collective bargaining agreements with Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 related to CERC employees in Minnesota, as well as with IBEW Local 702 related to SIGECO employees, are scheduled to expire in April 2025, December 2025, December 2025 and June 2025, respectively, and negotiations of these agreements are expected to be completed before the respective expirations. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have an adverse effect on our businesses, results of operations and/or cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have an adverse effect on our businesses, results of operations and cash flows.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B.Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2.Properties
The following discussion is based on the Registrants’ businesses as of December 31, 2024.
Character of Ownership
We lease or own our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and natural gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.
Electric (CenterPoint Energy and Houston Electric)
Properties
All of Houston Electric’s properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires, telecommunications networks and meters. Most of Houston Electric’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets under franchise agreements and as permitted by law.
All real and tangible properties of Houston Electric, subject to certain exclusions, are currently subject to the lien of the M&DOT and the lien of the General Mortgage, which is junior to the lien of the M&DOT.
No first mortgage bonds are outstanding under the M&DOT and Houston Electric is contractually obligated to not issue any additional first mortgage bonds under the M&DOT. Houston Electric is undertaking actions to release the lien of the M&DOT and terminate the M&DOT. For information related to debt outstanding under the General Mortgage, see Note 12 to the consolidated financial statements.
Indiana Electric’s properties are primarily located in Indiana. They consist of transmission lines in Indiana and Kentucky, distribution lines, substations, service centers, coal-fired generating facilities, gas-fired turbine peaking units, a landfill gas electric generation project and solar generation facilities.
All real and tangible properties of Indiana Electric, subject to certain exclusions, are currently subject to the lien of the Amended and Restated Mortgage Indenture dated as of January 1, 2023, between SIGECO (Indiana Electric) and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee.
Electric Lines - Transmission and Distribution. As of December 31, 2024, Houston Electric and Indiana Electric owned and operated the following electric transmission and distribution lines:
Houston Electric Indiana Electric
Description Overhead Lines Underground Lines Indiana Kentucky (1)
Transmission lines: (in Circuit Miles)
69 kV 109 2 568 -
138 kV 2,347 24 422 9
345 kV 1,445 - 49 15
Total 3,901 26 1,039 24
Distribution lines 29,327 27,000 7,318 -
(1)These assets interconnect with Louisville Gas and Electric Company’s transmission system at Cloverport, Kentucky and with Big Rivers Electric Cooperative at Sebree, Kentucky.
Generating Capacity. As of December 31, 2024, Indiana Electric had 577 MW of installed generating capacity, as set forth in the following table:
Generation Source Unit No. Location Date in Service Capacity
(MW)
Coal
F.B. Culley 2 Warrick County, Indiana
1966 90
F.B. Culley 3 Warrick County, Indiana
1973 270
Total Coal Capacity 360
Gas
Brown (1)
3 Posey County, Indiana
1991 80
Brown 4 Posey County, Indiana
2002 80
Renewable Landfill Gas Pike County, Indiana
2009 3
Total Gas Capacity 163
Solar
Oak Hill Evansville, Indiana 2018 2
Volkman Evansville, Indiana 2018 2
Troy Spencer County, Indiana
2021 50
Total Solar Capacity 54
Total Generating Capacity (2)
(1)Brown Unit 3 is also equipped to burn oil.
(2)Excludes 1.5% participation in OVEC. See Item 1. Business for more details.
Natural Gas Combustion Turbines. In 2022, Indiana Electric received approval from the IURC for a CPCN seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. The turbines are targeted to be operational by mid-year 2025. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
Solar. Indiana Electric entered into an amended and restated BTA to build a 191 MW solar array in Posey County, Indiana, , and a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price; however on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate this BTA. For further information about Indiana Electric’s BTA’s, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.
Temporary Generation. As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event and amended in 2023, Houston Electric is leasing TEEEF that can aid in restoring power to customers during certain significant power outages that are impacting its distribution system. On December 19, 2024, Houston Electric announced a proposal to release certain of Houston Electric’s TEEEF to the San Antonio area prior to the summer of 2025 for a period of up to two years, during which Houston Electric would not receive revenue or profit from ERCOT and would not charge Houston-area customers for these TEEEF units. As of December 31, 2024, Houston Electric leased 505 MW of TEEEF. For more information, see Note 7 and Note 19 to the consolidated financial statements.
Substations. A substation is a facility that transforms electricity from a higher voltage to a lower voltage or vice versa. Generally, this facility is the interface between the transmission system and the distribution grid. The following table presents certain information related to CenterPoint Energy’s substations as of December 31, 2024:
Number of Substations Transformer Capacity (in Mva)
Houston Electric 243 73,667
Indiana Electric 109 6,992
Total CenterPoint Energy 352 80,659
Service Centers. Service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity. The following table presents certain information related to CenterPoint Energy’s service centers as of December 31, 2024:
Number of
Service Centers
Acres of Land
Houston Electric 13 362
Indiana Electric 6 70
Total CenterPoint Energy 19 432
Natural Gas (CenterPoint Energy and CERC)
CenterPoint Energy’s and CERC’s Natural Gas use various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. CenterPoint Energy’s and CERC’s Natural Gas may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production.
As of December 31, 2024, CenterPoint Energy’s and CERC’s Natural Gas owned and operated the following natural gas facilities:
No. of Assets Storage Capacity (Bcf) Working Capacity (Bcf) Maximum Daily Withdrawal Rate (MMcf)
CenterPoint Energy
Underground Natural Gas Storage Facility 8 43 14 305
CERC
Underground Natural Gas Storage Facility 5 32 9 205
On-site Storage Capacity
No. of Assets Daily Production Rate (Dth) Millions of Gallons Dth
CenterPoint Energy and CERC
Propane Air-Gas Manufacturing Plant 15 247,000 14 1,228,000
LNG Plant Facility 1 72,000 12 1,010,000
The table below reflects CenterPoint Energy’s and CERC’s Natural Gas contracted upstream storage services as of December 31, 2024:
Storage Capacity (Bcf) Maximum Peak Daily Delivery (MMcf)
Upstream Storage Service 89 2,311
The table below reflects the approximate total linear miles of CenterPoint Energy’s and CERC’s Natural Gas distribution and transmission mains owned as of December 31, 2024:
CenterPoint Energy CERC
All Locations 85,000 82,000
Indiana and Ohio 22,000 19,000
CenterPoint Energy’s and CERC’s Natural Gas owned mains varying in size from one-half inch to 24 inches in diameter. CenterPoint Energy’s and CERC’s Natural Gas Indiana and Ohio mains are located in Indiana and Ohio except for, in the case of CenterPoint Energy, pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported to customers in Indiana. Generally, in each of the cities, towns and rural areas served by CenterPoint Energy’s and CERC’s Natural Gas, they own the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure
maintenance. With a few exceptions, the measuring stations at which CenterPoint Energy’s and CERC’s Natural Gas receive gas are owned, operated and maintained by others, and their distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.
As of December 31, 2024, CenterPoint Energy and CERC, through CEIP, owned and operated over 219 miles of intrastate pipeline in Louisiana and Texas. On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses, which include the intrastate pipelines owned by CEIP in Louisiana. The transaction is expected to close in the first quarter of 2025. For further information, see Note 4 to the consolidated financial statements.

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ITEM 3. LEGAL PROCEEDINGS
Item 3.Legal Proceedings
For a discussion of material legal and regulatory proceedings, including environmental legal proceedings that involve a governmental authority as a party and that the Registrants reasonably believe would result in $1,000,000 or more of monetary sanctions, exclusive of interest and costs, under federal, state and local laws that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment, affecting the Registrants, read “Business - Regulation” and “Business - Environmental Matters” in Item 1 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Regulatory Matters” in Item 7 of Part II of this report and Note 14(d) to the consolidated financial statements, which information is incorporated herein by reference.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4.Mine Safety Disclosures
Not applicable.
PART II
This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp.

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
CenterPoint Energy
As of February 10, 2025, CenterPoint Energy’s common stock was held by approximately 21,495 shareholders of record. CenterPoint Energy’s common stock is listed on the NYSE and NYSE Chicago and is traded under the symbol “CNP.”
The amount of future cash dividends will be subject to determination based upon CenterPoint Energy’s financial condition and results of operations, future business prospects, any applicable contractual restrictions and other factors that CenterPoint Energy’s Board of Directors considers relevant and will be declared at the discretion of CenterPoint Energy’s Board of Directors. For further information on CenterPoint Energy’s dividends, see Note 11 to the consolidated financial statements.
Repurchases of Equity Securities
During the quarter ended December 31, 2024, none of CenterPoint Energy’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended, were purchased by or on behalf of CenterPoint Energy or any “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended.
Houston Electric
As of February 10, 2025, all of Houston Electric’s 1,000 outstanding common shares were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.
CERC
As of February 10, 2025, all of CERC Corp.’s 1,000 outstanding shares of common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following combined discussion and analysis should be read in combination with the consolidated financial statements included in Item 8 herein. The discussion of CenterPoint Energy’s consolidated financial information includes the results of CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp., which, along with CenterPoint Energy, Inc., are collectively referred to as the Registrants. Where appropriate, information relating to a specific registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this combined Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric and CERC, unless stated otherwise. No registrant makes any representations as to the information related solely to CenterPoint Energy, Inc. or the subsidiaries of CenterPoint Energy, Inc. other than itself.
OVERVIEW
Background
CenterPoint Energy is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution systems. For a detailed description of CenterPoint Energy’s operating subsidiaries, see Note 1 to the consolidated financial statements.
Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy, which provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas Gulf Coast area that includes the city of Houston.
CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, which (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi and Texas, (ii) indirectly, through Indiana Gas and CEOH, owns and operates natural gas distribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP.
On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 4 to the consolidated financial statements.
Reportable Segments
We discuss our operating results on a consolidated basis and individually for each of our reportable segments. We are first and foremost an energy delivery company and it is our intention to remain focused on these regulated segments. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject, among other factors.
Below is a summary of CenterPoint Energy’s reportable segments as of December 31, 2024. For a detailed description of the assets included in each reporting segment, see Part I, Item 1. Business.
•The Electric reportable segment includes electric transmission and distribution services that are subject to rate regulation in Houston Electric’s and Indiana Electric’s service territories, as well as the impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility and energy delivery services to electric customers and electric generation assets to serve electric customers and optimize those assets in the wholesale power market in Indiana Electric’s service territory.
•The Natural Gas reportable segment includes (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial and industrial customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas; (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; and (iii) home appliance maintenance and repair services to customers in Minnesota and home repair protection plans to natural gas customers in Indiana, Mississippi, Ohio and Texas through a third party.
•The Corporate and Other reportable segment includes (i) energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group; (ii) corporate operations that support the business operations of CenterPoint Energy; and (iii) office buildings and other real estate used for business operations.
Houston Electric and CERC each consist of a single reportable segment.
EXECUTIVE SUMMARY
We expect our businesses to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
Factors Influencing Our Businesses and Industry Trends
We are an energy delivery company with electric transmission and distribution, power generation, and natural gas distribution operations that serve more than seven million metered customers across six jurisdictions. The majority of our revenues are generated from the transmission and delivery of electricity and the sale of natural gas by our subsidiaries.
We continue to execute on our strategic goals for our businesses which were set in 2021. These include our ten-year capital plan from 2021 through 2030, a focus on targeting controllable operations and maintenance savings for the benefit of our customers, prudent capital funding including divestitures of non-core assets, and net zero and GHG emissions reduction goals. Our focus continues to be on the growth of our regulated utility businesses including our electric and gas utility operations, which comprise over 95% of our earnings for the year ended December 31, 2024. See Note 16 to the consolidated financial statements for further details.
Pursuant to this business strategy and in light of the nature of our businesses, significant amounts of capital investment are reflected in our current 10-year capital plan, which has increased to nearly $47.5 billion through 2030. These investments include a focus on additional system resiliency, reliability, and grid modernization. These investments are not only intended to meet our customers’ current needs, but are also in anticipation for further organic growth and load growth from increased electrification in our service territories. To fund these capital investments, we rely on internally-generated cash, borrowings under our credit facilities, proceeds from commercial paper, cash proceeds from strategic transactions (such as the divestitures of our Arkansas and Oklahoma LDC businesses in 2022, our Energy Systems Group divestiture in 2023 and the proposed sale of our Louisiana and Mississippi natural gas LDC businesses, which is expected to close in the first quarter of 2025), and issuances of equity and debt in the capital markets, including the issuance of non-recourse securitization bonds at Houston Electric related to costs incurred during the year ended December 31, 2024 due to the May 2024 Storm Events and Hurricane Beryl.
We strive to maintain investment grade ratings for our securities to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets along with high or rising interest rates can also affect the availability of new capital on terms we consider attractive. In those circumstances, we may not be able to obtain certain types of external financing or may be required to accept terms less favorable than we would otherwise accept which, among other things, would negatively impact our ability to finance our capital plan. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt.
The regulation of electric transmission, distribution and generation facilities as well as natural gas pipelines and related facilities by federal and state regulatory agencies affects our businesses. In accordance with applicable regulations, we are making, and will continue to make, significant capital investments in our service territories under our capital plan to help operate and maintain safer, more reliable and growing electric and natural gas systems. The current economic environment (e.g., sustained higher interest rates and higher relative levels of inflation in the United States) discussed further below could result in heightened regulatory scrutiny as these regulatory agencies seek to reduce the financial impact of utility bills on customers.
While greater than 80% of CenterPoint Energy’s projected consolidated investments are expected to be recovered through interim capital recovery trackers or rate cases based on a forward test year, the balance is expected to be recovered through base rate cases. Indiana Electric filed a rate case during 2023, and Houston Electric and CERC’s Ohio jurisdiction filed rate cases in 2024. The outcome of these base rate proceedings will determine, among other things, the ability to recover certain capital
investments within those jurisdictions. The outcome of these base rate proceedings is uncertain and may be impacted by the current economic environment. CERC’s Texas and Minnesota gas jurisdictions filed rate cases in 2023, which were settled in 2024. For additional detail, see “-Liquidity and Capital Resources -Regulatory Matters” below.
To assess our financial performance, our management primarily monitors the recovery of costs and return on investments by the evaluation of net income and capital expenditures, among other things, from our regulated service territories within our reportable segments. Within these broader financial measures, we monitor margins, natural gas and fuel costs, interest expense, capital spend, working capital requirements, and operation and maintenance expense. In addition to these financial measures, we also monitor a number of variables that management considers important to gauge the performance of our reportable segments, including the number of customers, throughput, commodity prices, heating and cooling degree days, environmental impacts, safety factors, system reliability and customer satisfaction.
CenterPoint Energy and CERC have weather normalization or other rate mechanisms that largely mitigate the impact of weather on Natural Gas in Indiana, Louisiana, Mississippi, Minnesota and Ohio, as applicable. CenterPoint Energy’s and CERC’s Natural Gas in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms, although fixed customer charges are historically higher in Texas for Natural Gas compared to its other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s Natural Gas’ results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories.
Each state has a unique economy and is driven by different industrial sectors. Our largest customers reflect the diversity in industries in the states across our footprint. For example, Houston Electric is largely concentrated in Houston, a diverse economy where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although the Houston area represents a large part of our customer base, we have a diverse customer base throughout the various states our utility businesses serve. In Minnesota, for instance, education and health services are the state’s largest sectors. Indiana and Ohio are impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest such as automotive, feed and grain processing. Some industries are driven by population growth like education and health care, while others may be influenced by strength in the national or international economy. Adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for our services. Long-term national trends indicate residential customers have reduced their energy consumption, which could adversely affect our results. To the extent population growth is affected by lower energy prices and there is financial pressure on some of our customers who operate within the energy industry, there may be an impact on the growth rate of our customer base and overall demand. Management expects residential meter growth for Houston Electric to remain in line with long term trends at approximately 2%. Management additionally anticipates significant increased electric load growth demand in our Houston Electric service territory, including in relation to the expected expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics. Typical customer growth in the jurisdictions served by the Natural Gas reportable segment is approximately 1%. Management expects residential meter growth for CERC to remain in line with long term trends at approximately 1%.
Inflation and high interest rates and a recessionary environment could potentially adversely impact CenterPoint Energy’s ability to execute on its 10-year capital plan. The inability to execute on our capital plan may result in lost future revenues for CenterPoint Energy. Additionally, these economic conditions may affect customers’ ability to pay their utility bills which may preclude our ability to collect balances due from such customers.
Further, the global supply chain has experienced significant disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and political instability, import tariffs and trade agreements, labor shortages, resource availability, long lead times, manufacturer production limitations, delivery delays, inflation and severe weather events. These disruptions have adversely impacted the utility industry. Like many of our peers, we have experienced disruptions to our supply chain, as well as increased prices, and may continue to experience such disruptions in the future. For example, President Trump has expressed a desire to impose substantial new or increased tariffs, and in February 2025, imposed tariffs on several countries and certain imports into the United States. These tariffs, as well as any new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could increase or cause volatility in the cost of and negatively impact our ability to procure materials, supplies (such as natural gas) or services necessary for our business and capital plan, lead to scarcity of resources and labor necessary for our business and capital plan, further extend lead time or otherwise negatively impact the supply chain and our ability to timely execute our capital plan. To the extent adverse economic conditions, including supply chain disruptions, affect our suppliers and customers as well as our ability to meet our capital plan and generation transition plan, including with respect to developing and constructing new generation facilities at the cost and scale and on the timelines that we anticipate, results from our energy delivery businesses may suffer. For more information, see Note 14 to the consolidated financial statements.
Further, in response to concerns for protecting the environment, we have strived to take a leading stance in the transition to safer and cleaner energy by being the first combined electric and natural gas utility with regulated generation assets to adopt net zero for its Scope 1 and certain Scope 2 emissions by 2035 goals. In addition, we set a Scope 3 emission reduction goal across our multi-state footprint by committing to help our residential and commercial customers reduce GHG emissions attributable to their end use of natural gas by 20% to 30% by 2035 from a 2021 baseline. Our capital plan supports these goals. For more information regarding CenterPoint Energy’s net zero and GHG emissions reduction goals and the risks associated with them, see Part I, Item 1A. “Risk Factors - Risk Factors Affecting Regulatory, Environmental and Legal Risks - CenterPoint Energy is subject to operational and financial risks...”
Significant Events
May 2024 Storm Events and Hurricane Beryl. Houston Electric’s service territory experienced sudden and destructive severe weather events in May 2024 that included hurricane-like winds and tornadoes. Subsequently, on July 8, 2024, Hurricane Beryl made landfall in Texas, bringing sustained winds, storm surges and torrential rain into Houston Electric’s service territory. The May 2024 Storm Events and Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in electric service interruptions peaking at an estimated 922,000 customers and more than 2.1 million customers, respectively.
Various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl, the efforts made by Houston Electric to prepare for, and respond to, this event, including the electric service outage issues, and the procurement of TEEEF. Moreover, additional governmental and regulatory agencies and other entities may conduct such inquiries and investigations, as well. On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl. Texas Lieutenant Governor Patrick has publicly urged the PUCT to hold Houston Electric, rather than ratepayers, responsible for paying $800 million, which was the amount the PUCT had previously approved Houston Electric to recover from ratepayers pursuant to Texas legislation passed after the 2021 Winter Storm Event relating to emergency responsiveness and the leasing of temporary generation units. Additionally, legislation has been proposed in Texas to, among other things, require the PUCT to review TEEEF leased by TDUs, disallow any leases that do not conform to the terms of the proposed legislation (which include, among other things, requirements relating to the speed with which TEEEF may be deployed), disallow recovery of costs associated with such disallowed leases, and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. There are significant uncertainties around these inquiries and investigations and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed or changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom. Further, on January 22, 2025, a putative shareholder of CenterPoint Energy, Donel Davidson, filed a derivative petition in Harris County District Court, Texas, alleging breach of fiduciary duty and unjust enrichment on behalf of CenterPoint Energy against certain of its current and former directors and officers citing, in part, the topics of these inquiries and investigations. The action seeks to recover damages and other relief from the defendants on behalf of CenterPoint Energy. Additionally, on February 12, 2025, a second putative shareholder of CenterPoint Energy made a demand on the Board to investigate the same basic allegations raised in the derivative petition filed by Donel Davidson.
Houston Electric announced an initial hurricane preparedness and response action plan to the PUCT on July 25, 2024 to enhance the resiliency of the electric system through various investments. Following a meeting with Texas Governor Abbott on August 1, 2024, Houston Electric publicly committed to accelerating its previously announced initial hurricane preparedness and response action plan. Accordingly, Houston Electric announced that it was withdrawing its application for approval of its transmission and distribution system resiliency plan with the PUCT in order to focus on addressing the impacts of Hurricane Beryl in its service territory and accelerating preparedness and resiliency efforts for the remaining storm season, and the withdrawal granted by the PUCT. On August 5, 2024, Houston Electric announced the launch of its GHRI. Subsequently, Houston Electric announced the completion of core resiliency actions as part of the first phase of its GHRI, which included certain vegetation management and pole installation goals. In September 2024, Houston Electric announced the launch of the second phase of its GHRI, which included a series of resiliency plans to install new poles, manage higher-risk vegetation and install certain automated devices prior to the start of the 2025 hurricane season as part of its efforts to strengthen grid resiliency, improve public and customer communications and strengthen local, community and emergency partnerships. Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed the SRP with the PUCT on January 31, 2025, which proposes investing approximately $5.75 billion over a three-year period for transmission and distribution infrastructure, information technology and cybersecurity assets, and event response capability.
Houston Electric announced on August 28, 2024 its proposal to forego approximately $110 million of profit related to its storm hardening and TEEEF efforts, which would be represented by (1) Houston Electric not seeking to recover approximately $70 million in incremental storm hardening costs incurred in connection with accelerated operational activities after Hurricane Beryl; and (2) Houston Electric not filing, beginning in 2028, for approximately $40 million in anticipated equity profit associated with load-shed orientated TEEEF leased by Houston Electric through the remaining regulatory life of the leases in 2032 as new dispatchable generation is likely to come online in the state of Texas as a result of the Texas Energy Fund. Additionally, on December 19, 2024, Houston Electric announced a proposal to release Houston Electric’s 15 large 27 MW to 32 MW TEEEF units to the San Antonio area prior to the summer of 2025 in an effort to help ERCOT address a potential energy shortfall and Load Shed risk and to provide additional electric generation capacity to support growing energy demand in the greater San Antonio region. Under the proposal, Houston Electric would not receive revenue or profit from ERCOT and would also not charge Houston-area customers for these TEEEF units for the period when they are in San Antonio serving ERCOT, which is currently expected to be for a period of up to two years. Houston Electric would anticipate receiving revenues from one or more future transactions after the period the units are utilized to temporarily serve an energy need in the San Antonio area, and would therefore plan to continue to not charge customers for these units for any future periods. As of the date of the filing of this Form 10-K, Houston Electric estimates that the value of the TEEEF units to be removed from the rate base as a result of the aforementioned proposal will be approximately $375 million. The proposal has not been finalized and is subject to the negotiation of definitive documentation among the relevant parties, as well as being subject to the approval of ERCOT and other stakeholders. It is not certain that mutually agreeable definitive documentation will be entered into at all or that all approvals will be obtained.
For more information, see Note 7, 12 and 14 to the consolidated financial statements and “Liquidity and Capital Resources” below.
Equity Transactions. On August 9, 2024, CenterPoint Energy issued 9,754,194 shares of Common Stock in an underwritten public offering at a price of $25.36 per share, for net proceeds of $247 million after deducting issuance costs. For further information, see Note 11 to the consolidated financial statements.
On January 10, 2024, CenterPoint Energy entered into an Equity Distribution Agreement with certain financial institutions with respect to the offering and sale from time to time of shares of Common Stock, having an aggregate gross sales price of up to $500 million. Sales of Common Stock may be made by any method permitted by applicable law and deemed to be an “at the market offering” as defined in Rule 415 of the Securities Act of 1933, as amended. CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations. During the year ended December 31, 2024, CenterPoint Energy issued 8,790,848 shares of Common Stock through the ATM Managers under the Equity Distribution Agreement, representing aggregate cash proceeds of $247 million, which was net of compensation paid by CenterPoint Energy to the ATM Managers of $2 million. As of December 31, 2024, CenterPoint Energy had not entered into any forward sale agreements under the at-the-market program. Additionally, as of December 31, 2024, CenterPoint Energy had $250 million of remaining capacity available under the program. For further information, see Note 11 to the consolidated financial statements.
Assets Held for Sale. On February 19, 2024, CERC Corp. entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The purchase price for the Louisiana and Mississippi natural gas LDC businesses is $1.2 billion and subject to adjustment as set forth in the LAMS Asset Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing. The transaction is not subject to a financing condition and is expected to close by the end of the first quarter of 2025, subject to satisfaction of customary closing conditions. The businesses include approximately 12,000 miles of main pipeline in Louisiana and Mississippi serving more than 300,000 customers. The Louisiana and Mississippi natural gas LDC businesses are reflected in CenterPoint Energy’s Natural Gas reportable segment and CERC’s single reportable segment, as applicable. For further information, see Note 4 to the consolidated financial statements.
Regulatory Proceedings. For further information, see Note 7 to the consolidated financial statements. For information related to our pending and completed regulatory proceedings to date in 2024 and to date in 2025, see “-Liquidity and Capital Resources -Regulatory Matters” below.
Debt Transactions. In 2024, CenterPoint Energy issued or borrowed a combined $4.0 billion in new debt, including Houston Electric’s issuance of $900 million aggregate principal amount of general mortgage bonds and a $500 million term loan, CERC’s issuance of $400 million principal amount of senior notes, SIGECO’s issuance of $160 million aggregate principal amount of first mortgage bonds, and CenterPoint Energy’s issuance of $700 million aggregate principal amount of senior notes and $1.3 billion aggregate principal amount of junior subordinated notes. During 2024, CenterPoint Energy repaid or redeemed a combined $0.9 billion of debt, including $500 million of its senior notes, $350 million of its floating rate senior notes and $22 million of SIGECO’s first mortgage bonds. For further information about debt transactions in 2024, see Note 12
to the consolidated financial statements.
Subsequent Events. On January 29, 2025, CenterPoint Energy, Houston Electric, CERC and SIGECO each entered into Extension Agreements to, among other things, extend the maturity date of the lenders’ commitments under each of their respective Credit Agreements by one year, from December 6, 2027 to December 6, 2028.
Additionally, on January 31, 2025, SIGECO issued $165 million aggregate principal amount of 5.69% First Mortgage Bonds, Series 2025A, Tranche A due 2055. Total net proceeds from SIGECO’s January 2025 issuance of first mortgage bonds, net of transaction expenses and fees, were approximately $164 million, which will be used for the acquisition of Posey Solar.
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors that apply to all Registrants unless otherwise indicated including:
•The business strategies and strategic initiatives, restructurings, joint ventures and acquisitions or dispositions of assets or businesses involving us or our industry, including the ability to successfully complete such strategies, initiatives, transactions or plans on the timelines we expect or at all, such as the announced sale of our Louisiana and Mississippi natural gas LDC businesses, which we cannot assure will have the anticipated benefits to us;
•industrial, commercial and residential growth in our service territories and changes in market demand, including in relation to the expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, as well as the effects of energy efficiency measures and demographic patterns;
•our ability to fund and invest planned capital and the timely recovery of our investments, including the timing of and amounts sought for those related to Indiana Electric’s generation transition plan as part of its IRPs and Houston Electric’s GHRI and SRP;
•our ability to successfully construct, operate, repair and maintain electric generating facilities, natural gas facilities, TEEEF and electric transmission facilities, including complying with applicable environmental standards and the implementation of a well-balanced energy and resource mix, as appropriate;
•timely and appropriate rate actions that allow and authorize timely recovery of costs and a reasonable return on investment, including the timing of and amounts sought for recovery of Houston Electric’s TEEEF leases and restoration costs relating to the May 2024 Storm Events and Hurricane Beryl, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings;
•our ability to finalize Houston Electric’s proposal to release its 15 large 27 MW to 32 MW TEEEF units to the San Antonio area and complete one or more other future transactions involving the units on acceptable terms and conditions within the anticipated timeframe;
•economic conditions in regional and national markets, including changes to inflation and interest rates, and their effect on sales, prices and costs;
•weather variations and other natural phenomena, including the impact of severe weather events on operations, capital, legislation and/or regulations, such as in connection with the February 2021 Winter Storm Event, the May 2024 Storm Events and Hurricane Beryl;
•volatility in the markets for natural gas as a result of, among other factors, tariffs, legislation, bans, potential retaliatory trade measures taken against the United States or related governmental action, as well as armed conflicts, including the conflict in the Middle East and any broader related conflict, and the conflict in Ukraine, and the related sanctions on certain Russian entities;
•disruptions to the global supply chain, including as a result of volatility in commodity prices, trade agreements, geopolitical and economic uncertainty, regulatory and policy instability, severe weather events, tariffs, bans, retaliatory trade measures, legislation and governmental action impacting the supply chain, that could prevent CenterPoint Energy from securing the resources needed to, among other things, fully execute on its 10-year capital plan or achieve its net zero and GHG emissions reduction goals;
•non-payment for our services due to financial distress of our customers and the ability of our customers, including REPs, to satisfy their obligations to CenterPoint Energy, Houston Electric and CERC, and the negative impact on such ability related to adverse economic conditions and severe weather events;
•public health threats, and their effect on our operations, business and financial condition, our industries and the communities we serve, U.S. and world financial markets and supply chains, potential regulatory actions and changes in customer and stakeholder behavior relating thereto;
•state and federal legislative and regulatory actions or developments affecting various aspects of our businesses, including, among others, any actions resulting from the May 2024 Storm Events and/or Hurricane Beryl, energy
deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses;
•our ability to execute Houston Electric’s GHRI and SRP;
•direct or indirect effects on our facilities, resources, operations, reputation and financial condition resulting from terrorism, cyberattacks or intrusions, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, derecho events, ice storms and other severe weather events, terrorism, wildfires, pandemic health events, geopolitical conflict or other occurrences;
•risks relating to potential wildfires, including damages to our network and losses in excess of insurance liability coverage;
•tax legislation, including the effects of or changes to or the repeal of the IRA (which includes but is not limited to any potential changes to tax rates, CAMT imposed, tax credits and/or interest deductibility), as well as any changes in tax laws under the current or future administrations, and uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates;
•our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;
•actions by credit rating agencies, including any potential downgrades to credit ratings;
•matters affecting regulatory approval, legislative actions, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or cancellation or in costs that cannot be recouped in rates;
•local, state and federal legislative and regulatory actions or developments relating to the environment, including, among others, those related to global climate change, air emissions, GHG emissions, carbon emissions, wastewater discharges and the handling and disposal of CCR that could impact operations, cost recovery of generation plant costs and related assets, and CenterPoint Energy’s net zero and GHG emissions reduction goals;
•the impact of unplanned facility outages or other closures;
•the sufficiency of our insurance coverage, including availability, cost, coverage and terms and ability to recover claims;
•the availability and prices of raw materials and services and changes in labor for current and future construction projects and operations and maintenance costs, including our ability to control such costs;
•impacts from CenterPoint Energy’s pension and postretirement benefit plans, such as the investment performance and increases to net periodic costs as a result of plan settlements and changes in assumptions, including discount rates;
•changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation;
•commercial bank and financial market conditions, including disruptions in the banking industry, our access to capital, the cost of such capital, the results of our financing and refinancing efforts, including availability of funds in the debt capital markets, and impacts on our vendors, customers and suppliers;
•inability of various counterparties to meet their obligations to us;
•the extent and effectiveness of our risk management activities;
•timely and appropriate regulatory actions, which include actions allowing requested securitization for any hurricanes or other severe weather events, such as the May 2024 Storm Events and Hurricane Beryl, or natural disasters or other amounts sought for recovery of costs, including stranded coal-fired generation asset costs;
•our ability to attract, effectively transition, motivate and retain management and key employees and maintain good labor relations;
•changes in technology, particularly with respect to efficient battery storage or the emergence or growth of new, developing or alternative sources of generation, and their adoption by consumers, and our ability to anticipate and adapt to technological changes;
•our success in adopting, developing and deploying AI;
•the impact of climate change and alternate energy sources on the demand for natural gas and electricity generated or transmitted by us;
•the timing and outcome of any audits, disputes and other proceedings related to taxes;
•the recording of impairment charges;
•political and economic developments and actions, including energy and environmental policies under the new presidential administration;
•CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including its net zero and GHG emissions reduction goals and its operations and maintenance expenditure goals;
•the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl;
•the effect of changes in and application of accounting standards and pronouncements; and
•other factors discussed in “Risk Factors” in Part I, Item 1A of this report and in other reports that the Registrants file from time to time with the SEC.
CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS
CenterPoint Energy’s results of operations are affected by seasonal fluctuations in the demand for electricity and natural gas. CenterPoint Energy’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates its subsidiaries charge, debt service costs, income tax expense, its subsidiaries ability to collect receivables from REPs and customers and its ability to recover its regulatory assets. For information regarding factors that may affect the future results of our consolidated operations, read “Risk Factors” in Part I, Item 1A of this report.
Income available to common shareholders for the years ended December 31, 2024, 2023 and 2022 was as follows:
Year Ended December 31, Favorable (Unfavorable)
2024 2023 2022 2024 to 2023
2023 to 2022
(in millions)
Electric $ 671 $ 654 $ 603 $ 17 $ 51
Natural Gas 564 533 492 31 41
Total Utility Operations 1,235 1,187 1,095 48 92
Corporate & Other (1) (216) (320) (87) 104 (233)
Total CenterPoint Energy $ 1,019 $ 867 $ 1,008 $ 152 $ (141)
(1)Includes energy performance contracting and sustainable infrastructure services through Energy Systems Group through the date of sale on June 30, 2023, unallocated corporate costs, interest income and interest expense, intercompany eliminations and the reduction of income allocated to preferred shareholders through September 1, 2023, the date of the redemption of all of the outstanding shares of the Series A Preferred Stock.
2024 Compared to 2023
CenterPoint Energy reported income available to common shareholders of $1,019 million for 2024 compared to income available to common shareholders of $867 million for 2023.
Income available to common shareholders increased $152 million primarily due to the following items:
•an increase in income available to common shareholders of $17 million for the Electric reportable segment, as further discussed below;
•an increase in income available to common shareholders of $31 million for the Natural Gas reportable segment, as further discussed below; and
•an increase in income available to common shareholders of $104 million for Corporate and Other, primarily due to $50 million of income allocated to holders of Series A Preferred Stock in 2023 prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023 as discussed in Note 11 to the consolidated financial statements, a loss on sale of $13 million and current tax expense of $32 million related to the divestiture of Energy Systems Group recorded in 2023 further discussed in Note 4 to the consolidated financial statements, $19 million due to remeasurement of deferred income tax balances recorded during 2023, as well as $8 million due to lower state income taxes. The remaining variance is due largely to an increase in borrowing costs.
2023 Compared to 2022
CenterPoint Energy reported income available to common shareholders of $867 million for 2023 compared to income available to common shareholders of $1,008 million for 2022.
Income available to common shareholders decreased $141 million primarily due to the following items:
•an increase in income available to common shareholders of $51 million for the Electric reportable segment, as further discussed below;
•an increase in income available to common shareholders of $41 million for the Natural Gas reportable segment, as further discussed below; and
•a decrease in income available to common shareholders of $233 million for Corporate and Other, primarily due to a pre-tax net gain of $86 million on the sale of Energy Transfer equity securities in 2022 further discussed in Note 10 to the consolidated financial statements, partially offset by $45 million of costs associated with early redemption of long-term debt in first quarter 2022. The decrease is also due to a loss on sale of $13 million and current tax expense of
$32 million related to the divestiture of Energy Systems Group further discussed in Note 4 to the consolidated financial statements, as well as $19 million due to remeasurement of deferred income tax balances. The remaining variance is due largely to an increase in borrowing costs.
Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements.
CENTERPOINT ENERGY’S RESULTS OF OPERATIONS BY REPORTABLE SEGMENT
CenterPoint Energy’s CODM views net income as the measure of profit or loss for the reportable segments. Segment results include inter-segment interest income and expense, which may result in inter-segment profit and loss.
The following discussion of CenterPoint Energy’s results of operations is separated into two reportable segments, Electric and Natural Gas.
Electric (CenterPoint Energy)
The following table provides summary data of CenterPoint Energy’s Electric reportable segment:
Year Ended December 31, Favorable (Unfavorable)
2024 2023 2022 2024 to 2023 2023 to 2022
(in millions, except throughput, weather and customer data)
Revenues $ 4,590 $ 4,290 $ 4,108 $ 300 $ 182
Expenses:
Utility natural gas, fuel and purchased power 198 176 222 (22) 46
Operation and maintenance 2,072 1,880 1,864 (192) (16)
Depreciation and amortization 877 872 793 (5) (79)
Taxes other than income taxes 304 272 275 (32) 3
Total expenses 3,451 3,200 3,154 (251) (46)
Operating Income 1,139 1,090 954 49 136
Other Income (Expense):
Interest expense and other finance charges (372) (303) (235) (69) (68)
Other income, net
61 56 31 5 25
Income Before Income Taxes
828 843 750 (15) 93
Income tax expense 157 189 147 32 (42)
Net Income
$ 671 $ 654 $ 603 $ 17 $ 51
Throughput (in GWh):
Residential 34,190 35,166 35,074 (3) % - %
Total 110,831 108,766 105,541 2 % 3 %
Weather (percentage of normal weather for service area):
Cooling degree days 115 % 114 % 110 % 1 % 4 %
Heating degree days 76 % 90 % 121 % (14) % (31) %
Number of metered customers at end of period:
Residential 2,640,150 2,588,510 2,534,730 2 % 2 %
Total 2,971,730 2,916,028 2,858,203 2 % 2 %
The following table provides variance explanations by major income statement caption for the Electric reportable segment:
Favorable (Unfavorable)
2024 to 2023 2023 to 2022
(in millions)
Revenues
Customer rates and impact of the change in rate design $ 143 $ 167
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below
217 122
Customer growth 26 26
Energy efficiency, offset in operation and maintenance below
5 -
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (20) (5)
Pass-through revenues, offset in operation and maintenance below (5) (13)
Miscellaneous revenues, including service connections and off-system sales
1 (14)
Lost revenues as a result of outages associated with Hurricane Beryl
(10) -
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below (70) (27)
Weather, efficiency improvements and other usage impacts (9) (28)
Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below 22 (46)
Total $ 300 $ 182
Utility natural gas, fuel and purchased power
Cost of purchased power, offset in revenues above $ (87) $ 30
Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above 65 16
Total
$ (22) $ 46
Operation and maintenance
Transmission costs billed by transmission providers, offset in revenues above $ (124) $ (26)
Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl
(112) -
Contract services 16 (21)
Energy efficiency, and other pass-through, offset in revenues above
(1) 3
Corporate support services
- (8)
Labor and benefits 4 7
All other operation and maintenance expense, including materials and supplies and insurance 25 29
Total $ (192) $ (16)
Depreciation and amortization
Ongoing additions to plant-in-service $ (79) $ (106)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 74 27
Total $ (5) $ (79)
Taxes other than income taxes
Incremental capital projects placed in service, and the impact of updated property tax rates
$ (26) $ 2
Franchise fees and other taxes (6) 1
Total $ (32) $ 3
Interest expense and other finance charges
Changes in outstanding debt $ (63) $ (76)
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (4) (4)
Other, primarily AFUDC and impacts of regulatory deferrals (2) 12
Total $ (69) $ (68)
Other income (expense), net
Other income, including AFUDC - equity $ 5 $ 21
Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above - 4
Total $ 5 $ 25
Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements.
Natural Gas (CenterPoint Energy)
The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment:
Year Ended December 31, Favorable (Unfavorable)
2024 2023 2022 2024 to 2023 2023 to 2022
(in millions, except throughput, weather and customer data)
Revenues $ 4,048 $ 4,279 $ 4,946 $ (231) $ (667)
Expenses:
Utility natural gas and fuel
1,520 1,888 2,665 368 777
Non-utility cost of revenues, including natural gas 3 3 4 - 1
Operation and maintenance 881 949 919 68 (30)
Depreciation and amortization 542 513 466 (29) (47)
Taxes other than income taxes 237 245 261 8 16
Total expenses 3,183 3,598 4,315 415 717
Operating Income 865 681 631 184 50
Other Income (Expense):
Gain on sale - - 303 - (303)
Interest expense and other finance charges (207) (188) (137) (19) (51)
Other income (expense), net 14 15 (62) (1) 77
Income Before Income Taxes
672 508 735 164 (227)
Income tax expense (benefit)
108 (25) 243 (133) 268
Net Income $ 564 $ 533 $ 492 $ 31 $ 41
Throughput (in Bcf):
Residential 189 199 240 (5) % (17) %
Commercial and industrial 426 418 424 2 % (1) %
Total Throughput 615 617 664 - % (7) %
Weather (percentage of 10-year average for service area):
Heating degree days 78 % 86 % 106 % (8) % (20) %
Number of metered customers at end of period:
Residential 4,063,928 4,010,113 3,964,221 1 % 1 %
Commercial and industrial 304,606 303,841 301,834 - % 1 %
Total 4,368,534 4,313,954 4,266,055 1 % 1 %
The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment:
Favorable (Unfavorable)
2024 to 2023 2023 to 2022
(in millions)
Revenues
Cost of natural gas, offset in utility natural gas and fuel below
$ (368) $ (754)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - (38)
Gross receipts tax, offset in taxes other than income taxes below 1 (17)
Weather and usage (11) (7)
Non-volumetric and miscellaneous revenue (7) 14
Energy efficiency and other pass-through, offset in operation and maintenance below (20) 17
Non-utility revenues
15 18
Customer growth 14 20
Customer rates
145 80
Total $ (231) $ (667)
Utility natural gas and fuel
Cost of natural gas, offset in revenues above $ 368 $ 754
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 23
Total $ 368 $ 777
Non-utility costs of revenues, including natural gas
Non-utility cost of revenues, including natural gas $ - $ 1
Total $ - $ 1
Operation and maintenance
All other operations and maintenance expenses, including bad debt expense
$ 23 $ (36)
Energy efficiency and other pass-through, offset in revenues above 20 (17)
Contract services (6) (3)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 3
Labor and benefits
8 11
Corporate support services 23 12
Total $ 68 $ (30)
Depreciation and amortization
Ongoing additions to plant-in-service
$ (29) $ (49)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 2
Total $ (29) $ (47)
Taxes other than income taxes
Gross receipts tax, offset in revenues above
$ (1) $ 17
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 1
Incremental capital projects placed in service, and the impact of updated property tax rates
9 (2)
Total $ 8 $ 16
Gain on Sale
Gain on Sale of Arkansas and Oklahoma Natural Gas businesses in 2022 $ - $ (303)
Total $ - $ (303)
Interest expense and other finance charges
Changes in outstanding debt $ (12) $ (59)
Other, primarily AFUDC and impacts of regulatory deferrals (7) 8
Total $ (19) $ (51)
Other income (expense), net
Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60
Other income, including AFUDC - Equity
3 10
Other
(7) 7
Total $ (1) $ 77
Income Tax Expense (Benefit). For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements.
HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS
Houston Electric’s CODM views net income as the measure of profit or loss for its reportable segment. Houston Electric consists of a single reportable segment. Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and Houston Electric’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of Houston Electric’s consolidated operations, read “Risk Factors” in Item 1A of Part I of this report.
The following table provides summary data of Houston Electric’s single reportable segment:
Year Ended December 31, Favorable (Unfavorable)
2024 2023 2022 2024 to 2023 2023 to 2022
(in millions, except throughput, weather and customer data)
Revenues:
TDU $ 3,862 $ 3,514 $ 3,205 $ 348 $ 309
Bond Companies 77 163 207 (86) (44)
Total revenues 3,939 3,677 3,412 262 265
Expenses:
Operation and maintenance, excluding Bond Companies 1,923 1,669 1,647 (254) (22)
Depreciation and amortization, excluding Bond Companies 688 593 479 (95) (114)
Taxes other than income taxes 295 262 261 (33) (1)
Bond Companies 78 159 194 81 35
Total 2,984 2,683 2,581 (301) (102)
Operating Income 955 994 831 (39) 163
Other Income (Expense):
Interest expense and other finance charges (311) (259) (202) (52) (57)
Interest expense on Securitization Bonds (3) (8) (13) 5 5
Other income, net 43 34 19 9 15
Income Before Income Taxes
684 761 635 (77) 126
Income tax expense
138 168 125 30 (43)
Net Income
$ 546 $ 593 $ 510 $ (47) $ 83
Throughput (in GWh):
Residential 32,769 33,830 33,676 (3) % - %
Total 106,014 103,862 100,062 2 % 4 %
Weather (percentage of 10-year average for service area):
Cooling degree days 115 % 114 % 110 % 1 % 4 %
Heating degree days 92 % 92 % 120 % - % (28) %
Number of metered customers at end of period:
Residential 2,506,284 2,455,309 2,402,329 2 % 2 %
Total 2,818,343 2,763,535 2,706,598 2 % 2 %
The following table provides variance explanations by major income statement caption for Houston Electric:
Favorable (Unfavorable)
2024 to 2023
2023 to 2022
(in millions)
Revenues
Customer rates and impact of the change in rate design $ 153 $ 187
Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below
217 120
Customer growth 25 25
Energy efficiency, partially offset in operation and maintenance below 5 1
Miscellaneous revenues 1 (4)
Lost revenues as a result of outages associated with Hurricane Beryl
(10) -
Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (19) (5)
Weather, efficiency improvements and other usage impacts
(24) (15)
Bond Companies, offset in other line items below (86) (44)
Total $ 262 $ 265
Operation and maintenance, excluding Bond Companies
Transmission costs billed by transmission providers, offset in revenues above $ (124) $ (26)
Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl
(112) -
Contract services 7 (23)
Energy efficiency, offset in revenues above
(6) (8)
Corporate support services
(2) (6)
Labor and benefits 1 3
All other operation and maintenance expense, including materials and supplies and insurance (18) 38
Total $ (254) $ (22)
Depreciation and amortization, excluding Bond Companies
Ongoing additions to plant-in-service $ (95) $ (114)
Total $ (95) $ (114)
Taxes other than income taxes
Franchise fees and other taxes $ (7) $ (2)
Incremental capital projects placed in service, and the impact of changes to tax rates (26) 1
Total $ (33) $ (1)
Bond Companies expense
Operations and maintenance and depreciation expense, offset in revenues above
$ 81 $ 35
Total $ 81 $ 35
Interest expense and other finance charges
Changes in outstanding debt $ (55) $ (64)
Other, primarily AFUDC and impacts of regulatory deferrals 3 7
Total $ (52) $ (57)
Interest expense on Securitization Bonds
Lower outstanding principal balance, offset in revenues above
$ 5 $ 5
Total $ 5 $ 5
Other income, net
Other income, including AFUDC - equity $ 9 $ 11
Bond Companies - 4
Total $ 9 $ 15
Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements.
CERC CONSOLIDATED RESULTS OF OPERATIONS
CERC’s CODM views net income as the measure of profit or loss for its reportable segment. CERC consists of a single reportable segment. CERC’s results of operations are affected by seasonal fluctuations in the demand for natural gas. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates CERC charges, debt service costs and income tax expense, CERC’s ability to collect receivables from customers and CERC’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of CERC’s consolidated operations, read “Risk Factors” in Item 1A of Part I of this report.
The following table provides summary data of CERC’s single reportable segment:
Year Ended December 31, Favorable (Unfavorable)
2024 2023 2022 2024 to 2023 2023 to 2022
(in millions, except throughput, weather and customer data)
Revenues
$ 3,925 $ 4,149 $ 4,800 $ (224) $ (651)
Expenses:
Utility natural gas 1,489 1,856 2,607 367 751
Non-utility cost of revenues, including natural gas 3 3 4 - 1
Operation and maintenance 848 904 886 56 (18)
Depreciation and amortization 522 493 448 (29) (45)
Taxes other than income taxes 234 243 257 9 14
Total expenses 3,096 3,499 4,202 403 703
Operating Income 829 650 598 179 52
Other Income (Expense):
Gain on sale - - 557 - (557)
Interest expense and other finance charges (197) (178) (130) (19) (48)
Other income (expense), net 12 14 (64) (2) 78
Income Before Income Taxes 644 486 961 158 (475)
Income tax expense (benefit) 104 (26) 236 (130) 262
Net Income $ 540 $ 512 $ 725 $ 28 $ (213)
Throughput (in BCF):
Residential 184 194 233 (5) % (17) %
Commercial and Industrial
390 386 389 1 % (1) %
Total Throughput 574 580 622 (1) % (7) %
Weather (percentage of 10-year average for service area):
Heating degree days 78 % 86 % 106 % (8) % (20) %
Number of metered customers at end of period:
Residential 3,958,584 3,905,388 3,859,726 1 % 1 %
Commercial and Industrial
293,959 293,235 291,184 - % 1 %
Total 4,252,543 4,198,623 4,150,910 1 % 1 %
The following table provides variance explanations by major income statement caption for CERC:
Favorable (Unfavorable)
2024 to 2023
2023 to 2022
(in millions)
Revenues
Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (367) $ (728)
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - (38)
Gross receipts tax, offset in taxes other than income taxes below
1 (15)
Weather and usage (9) (7)
Energy efficiency and other pass-through, offset in operation and maintenance below
(10) 8
Non-volumetric and miscellaneous revenue (6) 13
Non-utility revenues
15 18
Customer growth 13 20
Customer rates
139 78
Total $ (224) $ (651)
Utility natural gas
Cost of natural gas, offset in revenues above $ 367 $ 728
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 23
Total $ 367 $ 751
Non-utility costs of revenues, including natural gas
Other, primarily non-utility cost of revenues $ - $ 1
Total $ - $ 1
Operation and maintenance
All other operations and maintenance expenses, including bad debt expense
$ 21 $ (36)
Energy efficiency and other pass-through, offset in revenues above 10 (8)
Contract services (6) -
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 3
Labor and benefits 8 11
Corporate support services
23 12
Total $ 56 $ (18)
Depreciation and amortization
Ongoing additions to plant-in-service
$ (29) $ (47)
Indiana lower depreciation rates from recent rate order - -
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 2
Total $ (29) $ (45)
Taxes other than income taxes
Gross receipts tax, offset in revenues above
$ (1) $ 15
Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale - 1
Incremental capital projects placed in service, and the impact of updated property tax rates
10 (2)
Total
$ 9 $ 14
Gain on sale
Net gain on sale of Arkansas and Oklahoma Natural Gas businesses $ - $ (557)
Total $ - $ (557)
Interest expense and other finance charges
Changes in outstanding debt $ (11) $ (56)
Other, primarily AFUDC and impacts of regulatory deferrals (8) 8
Total $ (19) $ (48)
Other income (expense), net
Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60
Other income, including AFUDC - Equity
3 9
Other
(8) 9
Total $ (2) $ 78
Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following table summarizes the Registrants’ cash flows by category for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Cash provided by (used in):
Operating activities $ 2,139 $ 960 $ 1,068 $ 3,877 $ 1,401 $ 2,312 $ 1,810 $ 966 $ 856
Investing activities (4,489) (2,767) (1,419) (4,233) (2,503) (1,643) (1,628) (2,435) 406
Financing activities 2,271 1,732 352 374 1,103 (668) (345) 1,324 (1,277)
Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities:
2024 compared to 2023
2023 compared to 2022
CenterPoint Energy Houston Electric
CERC CenterPoint Energy Houston Electric
CERC
(in millions)
Changes in net income after adjusting for non-cash items $ 315 $ (132) $ 153 $ 394 $ 235 $ 170
Changes in working capital (134) 195 (83) 917 229 358
Changes in current regulatory assets and liabilities (1) (1,238) (4) (1,183) 1,085 26 986
Changes in non-current regulatory assets and liabilities (535) (472) (85) (276) (115) (78)
Lower pension contribution
2 - - 3 - -
Other (148) (28) (46) (56) 60 20
$ (1,738) $ (441) $ (1,244) $ 2,067 $ 435 $ 1,456
(1)This change is primarily related to the receipt of proceeds at CenterPoint Energy and CERC from the issuance of customer rate relief bonds Texas by the Natural Gas Securitization Finance Corporation in 2023. For further details, see Note 7 to the consolidated financial statements.
Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities:
2024 compared to 2023
2023 compared to 2022
CenterPoint Energy Houston Electric
CERC CenterPoint Energy Houston Electric
CERC
(in millions)
Proceeds from the sale of equity securities $ - $ - $ - $ (702) $ - $ -
Net change in capital expenditures (112) (363) 180 18 157 42
Net change in notes receivable from affiliated companies - 108 2 - (238) (1)
Proceeds from divestitures (144) - - (1,931) - (2,075)
Other - (9) 42 10 13 (15)
$ (256) $ (264) $ 224 $ (2,605) $ (68) $ (2,049)
Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities:
2024 compared to 2023
2023 compared to 2022
CenterPoint Energy Houston Electric
CERC CenterPoint Energy Houston Electric
CERC
(in millions)
Net changes in commercial paper outstanding $ 516 $ - $ 436 $ (981) $ - $ (227)
Net changes in proceeds from issuance of Common Stock 494 - - - - -
Net changes in long-term debt and term loans outstanding, excluding commercial paper 51 (6) 725 2,560 373 (778)
Net changes in debt and equity issuance costs 20 5 11 (19) 4 -
Net changes in short-term borrowings 6 - 6 (462) - (462)
Redemption of Series A Preferred Stock 800 - - (800) - -
Increased payment of Common Stock dividends (37) - - (45) - -
Decreased (increased) payment of preferred stock dividends 50 - - (1) - -
Payment of obligation for finance lease - - - 485 485 -
Net change in notes payable from affiliated companies - 642 - - (772) 1,517
Change in contribution from parent - (41) (210) - (258) 211
Change in dividend to parent - 28 54 - (51) 348
Other (3) 1 (2) (18) (2) -
$ 1,897 $ 629 $ 1,020 $ 719 $ (221) $ 609
Future Sources and Uses of Cash
Material Current and Long-term Cash Requirements. The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, storm restoration costs, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures (other than expenditures associated with the May 2024 Storm Events and Hurricane Beryl) are expected to be used for investment in infrastructure. These capital expenditures are anticipated to enhance reliability and safety, increase resiliency and expand our systems through value-added projects. Substantial capital expenditures are also expected for restoration costs associated with Hurricane Beryl, as further described below. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for 2025 include the following:
CenterPoint Energy Houston Electric CERC
(in millions)
Estimated capital expenditures (1)
$ 4,802 $ 2,560 $ 1,391
Estimated restoration costs associated with May 2024 Storm Events (2)
34 34 -
Estimated restoration costs associated with Hurricane Beryl (2)
102 102 -
Scheduled principal payments on Securitization Bonds
13 - -
Expected contributions to pension plans and other postretirement plans
120 1 5
(1)Excludes expenditures for the restoration costs associated with the May 2024 Storm Events and Hurricane Beryl.
(2)Represents cash requirements associated with estimated storm restoration costs for 2025.
The Registrants expect that anticipated cash needs for 2025 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, including the issuance of non-recourse securitization bonds at Houston Electric related to costs incurred during the year ended December 31, 2024 due to the May 2024 Storm Events and Hurricane Beryl, anticipated cash flows from operations, and, with respect to CenterPoint Energy and CERC, proceeds from commercial paper and the sale of the Louisiana and Mississippi natural gas LDC businesses, if and when completed (the transaction is expected to close in the first quarter of 2025). Issuances of debt securities in the capital markets, funds raised in the commercial paper markets, term loans and additional credit facilities may not, however, be available on acceptable terms. The Registrants may, from time to time, redeem, repurchase or otherwise acquire their outstanding debt securities through open market purchases, tender offers or pursuant to the terms of such securities.
For more information regarding the May 2024 Storm Events and Hurricane Beryl, see Notes 7, 12 and 14 to the consolidated financial statements as well as “Risk Factors” in Part I, Item 1A of this report.
The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for 2025 through 2029. See Note 16 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2024.
2025 2026 2027 2028 2029
CenterPoint Energy (in millions)
Electric $ 3,306 $ 4,358 $ 4,266 $ 4,106 $ 2,728
Natural Gas 1,465 1,604 1,469 1,344 1,327
Corporate and Other 31 20 20 20 20
Total $ 4,802 $ 5,982 $ 5,755 $ 5,470 $ 4,075
Houston Electric (1)
$ 2,560 $ 3,432 $ 4,008 $ 3,904 $ 2,546
CERC (1)
$ 1,391 $ 1,486 $ 1,391 $ 1,271 $ 1,254
(1)Houston Electric and CERC each consist of a single reportable segment.
Capital Expenditures for Climate-Related Projects. As part of its approximately $47.5 billion 10-year capital expenditure plan, which concludes in 2030, CenterPoint Energy anticipates spending over $3 billion in lower-emissions energy investments and enablement, which may be used to support, among other things, renewable energy generation.
The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2024:
2025 2026 2027 2028 2029 Thereafter Total
(in millions)
CenterPoint Energy
Securitization Bonds (1) $ 13 $ 14 $ 14 $ 15 $ 16 $ 252 $ 324
Other long-term debt (1) (2) 51 2,260 1,306 2,048 919 13,738 20,322
Interest payments - Securitization Bonds (3) 16 16 15 14 13 85 159
Interest payments - other long-term debt (3) 967 937 852 771 671 7,596 11,794
Short-term borrowings 500 - - - - - 500
Commodity and other commitments (4) 805 822 664 578 555 3,059 6,483
Total cash requirements $ 2,352 $ 4,049 $ 2,851 $ 3,426 $ 2,174 $ 24,730 $ 39,582
Houston Electric
Other long-term debt (1) $ - 300 $ 300 $ 500 $ - $ 7,313 $ 8,413
Interest payments - other long-term debt (3) 378 351 339 335 309 3,809 5,521
Short-term borrowings 500 - - - - - 500
Total cash requirements $ 878 $ 651 $ 639 $ 835 $ 309 $ 11,122 $ 14,434
CERC
Long-term debt (1)
$ 10 $ 60 $ 625 $ 1,230 $ 30 $ 3,260 $ 5,215
Interest payments - long-term debt (3) 251 250 246 188 156 1,071 2,162
Commodity and other commitments (4) 631 597 513 470 456 1,544 4,211
Total cash requirements $ 892 $ 907 $ 1,384 $ 1,888 $ 642 $ 5,875 $ 11,588
(1)Balances reflect aggregate principal amounts outstanding and do not include unamortized discounts, premiums or issuance costs. See Note 12 to the consolidated financial statements for additional information.
(2)ZENS obligations are included in the 2029 column at their contingent principal amount of $9 million as of December 31, 2024. These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($558 million as of December 31, 2024), as discussed in Note 10 to the consolidated financial statements.
(3)The Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2024. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings.
(4)For a discussion of commodity and other commitments, see Note 14(a) to the consolidated financial statements.
The table above does not include the following:
•estimated future payments for expected future AROs primarily estimated to be incurred after 2029. See Note 3(c) to the consolidated financial statements for further information.
•expected contributions to pension plans and other postretirement plans in 2025. See Note 8(g) to the consolidated financial statements for further information.
•operating leases. See Note 19 to the consolidated financial statements for further information.
Off-Balance Sheet Arrangements
Other than Houston Electric’s general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy as discussed in Note 12 and guarantees as discussed in Note 14(c) to the consolidated financial statements) and short-term leases, the Registrants have no off-balance sheet arrangements.
Regulatory Matters
Houston Electric TEEEF
For information about Houston Electric’s TEEEF, see Note 7 to the consolidated financial statements.
Hurricane Beryl
For information about Hurricane Beryl, see Note 7 to the consolidated financial statements.
May 2024 Storm Events
For information about May 2024 Storm Events, see Note 7 to the consolidated financial statements.
February 2021 Winter Storm Event
For information about the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements.
Indiana Electric Securitization of Generation Retirements (CenterPoint Energy)
For further information about the issuance of SIGECO Securitization Bonds, see Note 7 to the consolidated financial statements.
Indiana Electric CPCN (CenterPoint Energy)
BTAs
On February 23, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to purchase the Posey Solar project. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing Indiana Electric to purchase the Posey Solar project through a BTA to acquire its solar array assets for a fixed purchase price and approved recovery of costs via a levelized rate over the anticipated 35-year life. Due to community feedback and rising project costs caused by inflation and supply chain issues affecting the energy industry, Indiana Electric, along with Arevon, the developer, announced plans in January 2022 to downsize the Posey Solar project to 191 MW. Indiana Electric collaboratively agreed to the scope change, and on February 1, 2023, Indiana Electric entered into an amended and restated BTA that was contingent on further IURC review and approval. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve the amended BTA. With the passage of the IRA, Indiana Electric can now pursue PTCs for solar projects. Indiana Electric requested that project costs, net of PTCs, be recovered in rate base rather than a levelized rate, through base rates or the CECA mechanism, depending on which provides more timely recovery. On September 6, 2023, the IURC issued an order approving the CPCN. The Posey Solar project is expected to be placed in service in the second quarter of 2025 and recovered through base rates.
On July 5, 2022, Indiana Electric entered into a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price. A CPCN for the project was filed with the IURC on July 29, 2022. On September 21, 2022, an agreement in principle was reached resolving all the issues between Indiana Electric and OUCC. The Stipulation and Settlement agreement was filed on October 6, 2022 and a settlement hearing was held on November 1, 2022. On January 11, 2023, the IURC issued an order approving the settlement agreement authorizing Indiana Electric to purchase and acquire the Pike County Solar project through a BTA and approved the estimated cost. The IURC also designated the
project as a clean energy project under applicable Indiana regulations, approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs exceeded the agreed upon levels in the BTA. After negotiations, Indiana Electric and the developer were not able to agree upon updated pricing. As a result, on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate the BTA, which terminated all further obligations of Indiana Electric with respect to the project.
On January 10, 2023, Indiana Electric filed a CPCN with the IURC to acquire a wind energy generating facility with installed capacity of 200 MWs through a BTA, consistent with its 2019/2020 IRP that calls for up to 300 MWs of wind generation. The wind project is located in MISO’s Central Region. Indiana Electric received approval from the IURC to recover the costs of the wind facility via the CECA mechanism, which the developer believes can be placed in service by the end of 2026. On June 6, 2023, the IURC issued an order approving the CPCN, thereby authorizing Indiana Electric to purchase the wind generating facility. However, as of the date of the filing of this Form 10-K, Indiana Electric has not entered into any definitive agreement relating to this wind energy generating facility, and it is not certain that a definitive agreement will be entered into at all.
PPAs
Indiana Electric also sought approval in February 2021 for a 100 MW solar PPA with Clenera, LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25-year life of the PPA. In October 2021, the IURC approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising project costs caused by inflation and supply chain issues affecting the energy industry, Clenera, LLC and Indiana Electric were compelled to renegotiate terms of the agreement to increase the PPA price. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with certain modifications. Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2026.
On August 25, 2021, Indiana Electric filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis, which is developing a solar project in Knox County, Indiana. On May 4, 2022, the IURC issued an order approving Indiana Electric to enter into both PPAs. In March 2022, when the results of the MISO interconnection study were completed, Origis advised Indiana Electric that the costs to construct the solar project in Knox County, Indiana had increased. The increase was largely driven by escalating commodity and supply chain costs impacting manufacturers worldwide. In August 2022, Indiana Electric and Origis entered into an amended PPA, which reiterated the terms contained in the previously approved Knox County solar PPA with certain modifications. On February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date will be delayed to 2026. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved Vermillion County solar PPA with Oriden with certain modifications. Revised purchase power costs were approved to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden. On May 30, 2023, the IURC approved the Vermillion County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2026.
On May 1, 2024, Indiana Electric filed with the IURC seeking approval to purchase 147 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Knox County, Illinois. On November 6, 2024, the IURC approved the Knox County wind PPA, which provided for the recovery of the purchase power costs through the fuel adjustment clause proceedings over the term of the PPA. The facility is targeted to be in operation in early 2026.
Natural Gas Combustion Turbines
On June 17, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. On June 28, 2022, the IURC approved the CPCN. The estimated $334 million turbine facility is being constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana and is expected to provide a combined output of 460 MW. Indiana Electric received approval for depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana Electric’s base rates include a return on and recovery of depreciation expense on the facility. A new approximately 23.5 mile pipeline will be constructed and operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. FERC granted a certificate to construct the pipeline on October 20, 2022. On January 7, 2025, the United States Court of Appeals for the D.C. Circuit affirmed the
FERC’s order granting the certificate. Indiana Electric granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. The facility is targeted to be operational by mid-year 2025. On February 6, 2025, the EPC contractor for Indiana Electric’s proposed natural gas combustion turbines provided a notice to Indiana Electric that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project. Recovery of the proposed natural gas combustion turbines and regulatory asset was included in the forecasted test year in the Indiana Electric rate case, which was filed with the IURC on December 5, 2023. For more information on the Indiana Electric rate case, see “- Rate Change Applications” below.
For more information regarding uncertainties related to our solar projects, see Part I, Item 1A of this combined Form 10-K and “ -Solar Panel Issues” below.
Culley Unit 3 Operations
In June 2022, F.B. Culley Unit 3, an Indiana Electric coal-fired electric generation unit with an installed generating capacity of 270 MW, experienced an operating issue relating to its boiler feed pump turbine. The unit returned to service in March 2023. In testimony filed September 13, 2023, the OUCC and an intervenor that represents industrial customers filed testimony with the IURC alleging that Indiana Electric did not act prudently which led to the unplanned outage and recommended disallowances between $21 million to $27 million. On July 3, 2024, the IURC issued an order finding Indiana Electric acted reasonably and prudently with respect to the events that gave rise to the Culley Unit 3 outage and, in addition, did not approve the intervenors proposed disallowance. The order is now final and non-appealable.
Space City Solar Transmission Interconnection Project (CenterPoint Energy and Houston Electric)
On December 17, 2020, Houston Electric filed a CCN with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first half of 2026.
Kilgore Transmission Project (CenterPoint Energy and Houston Electric)
On August 30, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Chambers County, Texas that will loop the existing 138 kV Chevron to Langston circuit number 86 on Houston Electric’s transmission system to Houston Electric’s planned Kilgore substation. On March 7, the PUCT issued a final order approving a route that was estimated to cost $60 million, including substation costs. The actual capital costs of the project, including the transmission line and the planned Kilgore substation, will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the second quarter of 2026.
Mill Creek Transmission Project (CenterPoint Energy and Houston Electric)
On November 17, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Harris and Montgomery Counties, Texas that will connect Houston Electric’s transmission system to Houston Electric’s planned Mill Creek substation. On November 21, 2024, the PUCT issued a final order approving a route estimated to cost $68 million. The actual capital costs of the project will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the first half of 2027.
Texas Legislation (CenterPoint Energy, Houston Electric and CERC)
Houston Electric and CERC were affected by legislation passed in 2023 and associated PUCT rulemaking projects, including the following pieces of legislation that became law during the 88th Texas Legislature, including:
•House Bill 1500 became effective on September 1, 2023 and continues the functions of the PUCT, the Office of Public Utility Counsel, and ERCOT through 2029. This bill also includes an amendment that clarifies the use cases under which TDUs may lease and operate temporary generation during “significant” power outages;
•House Bill 2263 became effective on June 12, 2023 and authorizes LDCs to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority;
•House Bill 2555 became effective on June 13, 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity, physical security, vegetation management and wildfire mitigation. On January 18, 2024, the PUCT issued an Order adopting its Resiliency Plan Rule (16 Tex. Admin. Code § 25.62);
•Senate Bill 947 became effective on September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages;
•Senate Bill 1015 became effective on June 18, 2023 and allows utilities to file the DCRF twice a year, on any day the PUCT is open (at least 185 days after filing a full base rate proceeding) and setting an administrative approval timeline of 60 days;
•Senate Bill 1016 became effective on May 5, 2023 and requires the PUCT to presume that all employee compensation and benefits are reasonable and necessary when establishing a utility’s rates if based upon market compensation studies issued within the last three years; it includes exceptions for utility officer incentives that are based on financial metrics. Certain incentive compensation that is in-line with market studies will be presumed reasonable and recoverable; and
•Senate Bill 1076 became effective on June 2, 2023 and moves the timeline for the PUCT to approve CCN for transmission projects to 180 days after the date of filing, rather than the first anniversary of the day it was filed.
The Registrants will monitor the 89th Texas Legislature for legislation that may impact their businesses.
Minnesota Legislation (CenterPoint Energy and CERC)
The Natural Gas Innovation Act was passed by the Minnesota legislature in June 2021 with bipartisan support. This law establishes a regulatory framework to enable the state’s investor-owned natural gas utilities to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions and advancing the state’s clean energy future. The maximum allowable cost for an innovation plan will start at 1.75% of the utility's revenue in the state and could increase to 4% by 2033, subject to review and approval by the MPUC. Specifically, the Natural Gas Innovation Act allows a natural gas utility to submit an innovation plan for approval by the MPUC that can propose the use of renewable energy resources and innovative technologies such as:
•renewable natural gas (produces energy from organic materials such as wastewater, agricultural manure, food waste, agricultural or forest waste);
•renewable hydrogen gas (produces energy from water through electrolysis with renewable electricity such as solar);
•energy efficiency measures (avoids energy consumption in excess of the utility’s existing conservation programs); and
•innovative technologies (reduces or avoids GHG emissions using technologies such as carbon capture).
On June 28, 2023, CERC submitted its first innovation plan to the MPUC; the five-year plan includes 18 pilot projects and seven smaller research-and-development projects. These projects will deploy and evaluate a broad array of innovative resources including made-in-Minnesota alternative gases such as renewable natural gas and green hydrogen, as well as pioneering technologies such as a networked geothermal district energy system and end-use carbon capture. The proposed plan requires approval from the MPUC through a review process that is expected to take about one year. The MPUC requested comments by September 15, 2023 if parties believe that the filing is incomplete based on the reporting requirements or if parties do not believe that that the MPUC’s standard informal proceeding process is appropriate. No parties filed comments regarding completeness or raising concerns that the MPUC’s standard informal procedural process is inappropriate. The initial comment period closed on January 15, 2024, the reply comment period closed on March 15, 2024 and the supplemental comment period closed on May 15, 2024. On July 25, 2024, the MPUC voted to approve the plan with some minor modifications during its agenda meeting and a formal order was issued on October 9, 2024.
Solar Panel Issues (CenterPoint Energy)
CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs. The potential delays and inflationary cost pressures communicated from the developers of our solar projects have been primarily due to (i) unavailability of solar panels and other uncertainties related to DOC antidumping and countervailing duties investigation(s), (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On May 15, 2024, based on a petition filed by the American Alliance for Solar Manufacturing Trade Committee, the DOC announced the
initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells from Cambodia, Malaysia, Thailand, and Vietnam. On October 1, 2024, the DOC’s preliminary countervailing duty determination affirmed the petition and established preliminary duty rates. A final determination is expected in the first quarter of 2025. On November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates. A final determination is expected in the second quarter of 2025. These impacts could result in cost increases for certain projects, and such impacts may require that we seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects. For more information regarding potential delays, cancellations and supply chain disruptions, see “Part I, Item 1A. Risk Factors- Risk Factors Affecting Operations - Electric Generation, Transmission and Distribution - Increases in the cost or...” in this report.
TDSIC 2.0 (CenterPoint Energy)
On May 24, 2023, Indiana Electric filed its petition and case-in-chief with the IURC requesting, among other things, approval of its five-year plan for transmission, distribution, and storage improvements (TDSIC Plan) and an order approving the TDSIC Plan was issued on December 27, 2023. The approved five-year TDSIC Plan, covering the period January 1, 2024 through December 31, 2028, consists of approximately $454 million in proposed investments across seven different programs: (1) Distribution 12kV Circuit Rebuild, (2) Distribution Underground Rebuild, (3) Distribution Automation, (4) Wood Pole Replacement, (5) Transmission Line Rebuild, (6) Substation Rebuild, and (7) Substation Physical Security.
Transmission and Distribution System Resiliency Plans (CenterPoint Energy and Houston Electric)
House Bill 2555, codified as Tex. Util. Code § 38.078, was passed by the 88th Texas Legislature in 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT to enhance the resiliency of the utility’s transmission system through at least one or more of the following measures: hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity measures, physical security measures, vegetation management, and wildfire mitigation and response. House Bill 2555 also allows an electric utility to establish a regulatory asset for distribution-related costs, including depreciation expense and carrying costs at the electric utility’s weighted average cost of capital, relating to the implementation of a transmission and distribution system resiliency plan.
On April 29, 2024, Houston Electric filed its first transmission and distribution system resiliency plan with the PUCT, which proposed to implement 25 resiliency measures over a three-year period. On August 1, 2024, Houston Electric announced that it was withdrawing its application for approval of its transmission and distribution system resiliency plan in order to focus on addressing the impacts of Hurricane Beryl and accelerating preparedness and resiliency efforts for the remaining storm season. The ALJ granted Houston Electric’s request for withdrawal of the transmission and distribution system resiliency plan on August 16, 2024. Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed the SRP with the PUCT on January 31, 2025 for review and approval. Anticipated to benefit Houston Electric customers by saving approximately 1.3 billion customer minutes of interruption, the SRP proposes to invest approximately $5.75 billion over a three-year period from 2026 to 2028 for transmission and distribution infrastructure, information technology and cybersecurity assets and event response capability. This plan proposes 39 resiliency-enhancing measures and a microgrid pilot program to be implemented over the three-year period. The SRP has an estimated capital cost of approximately $5.54 billion and an estimated operations and maintenance expense of approximately $211 million. Approximately $2.17 billion of such cost is for transmission-related investments, and approximately $3.58 billion is for distribution-related investments.
Rate Change Applications
The Registrants are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Registrants are periodically involved in proceedings to adjust their capital tracking mechanisms (e.g., CSIA, DCRF, DRR, GRIP, TCOS, ECA, CECA and TDSIC), their cost of service adjustments (e.g., RSP and RRA), their decoupling mechanism (e.g., decoupling and SRC), and their energy efficiency cost trackers (e.g., CIP, DSMA, EECR, EECRF, EEFC and EEFR).
Texas Gas Rate Case. On October 30, 2023, CERC filed an application with the Railroad Commission and municipal regulatory authorities to set new natural gas base rates that would be applied consistently across the approximately 1.9 million customers. The need for a rate change was primarily driven by the continuing investment in the safety and reliability of the natural gas system, including new Intelis natural gas meters that feature an integrated safety shutoff valve, changes to depreciation rates that better reflect the actual life and salvage characteristics of assets, and changes in other costs to serve customers. A settlement agreement was filed on April 23, 2024. The settlement agreement was approved by the Railroad Commission on June 25, 2024 and provides for a $5 million annual increase in current revenues and establishes a 9.80% ROE and a 60.61% equity ratio for future GRIP filings. New rates became effective in December 2024.
Minnesota Gas Rate Case. On November 1, 2023, CERC filed an application with the MPUC requesting an adjustment to delivery charges in 2024 and 2025 for the natural gas business in Minnesota. The requested increase is approximately 6.5% or $85 million for 2024 and an additional approximately 3.7% or $52 million for 2025. The need for a rate change is primarily driven by the continuing investment in the safety and reliability of the natural gas system, including new Intelis natural gas meters that feature an integrated safety shutoff valve, changes to depreciation rates that better reflect the actual life and salvage characteristics of assets, and changes in other costs to serve customers. The request reflects a proposed 10.3% ROE on a 52.5% equity ratio. Interim rates for 2024 of $69 million, subject to refund, were implemented as of January 1, 2024. A request for interim rates of $33 million for 2025 was filed on September 30, 2024, approved at the December 3, 2024 hearing and approved by an order issued December 20, 2024. A unanimous settlement agreement was filed on November 25, 2024. The settlement provided for an increase of $60.8 million for 2024 and an additional $42.7 million for 2025. The parties agreed to an overall cost of capital of 7.07% for 2024 and 2025. The Administrative Law Judge filed a report on February 13, 2025 recommending the Commission approve the settlement agreement. The anticipated decision date of the rate case is July 1, 2025.
Indiana Electric Rate Case. On December 5, 2023, Indiana Electric filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase is approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase is primarily driven by the continuing investment in the safety and reliability of the system and normal increases in operating expenses. The initial filing of the rate case reflected a proposed 10.4% ROE on a forecasted 55% equity ratio. Indiana Electric reached a settlement agreement with less than all parties and submitted the agreement to the IURC on May 20, 2024. The settlement reflects a proposed 9.8% ROE on a forecasted 55% equity ratio. The requested increase was lowered to $80 million, an 11% increase. Indiana Electric received a final order on February 3, 2025 approving the settlement with one modification that effectively capped the residential increase to 1.15% of the total increase, allocating the difference to other commercial and industrial customers. The final order approves the 9.8% ROE on a forecasted 55% equity ratio and increases revenues by $80 million.
Houston Electric Rate Case. On March 6, 2024, Houston Electric filed an application with the PUCT requesting authority to change rates and charges for electric transmission and distribution service. The requested increase is approximately $17 million (1%) for retail customers and $43 million (6.6%) for wholesale transmission service, excluding TCRF and rate case expenses. The need for a rate increase is primarily driven by the continuing investment that has been made to support customer growth and to bolster the safety and reliability of Houston Electric’s transmission and distribution system. The request reflects a proposed 10.4% ROE and a 45% equity ratio. Errata testimony was filed to correct minor errors included in the initial filing which reduced the requested increase to $56 million compared to current rates. On January 15, 2025, Houston Electric filed a letter indicating that an agreement in principle had been reached with certain parties and that complete settlement documents would be filed as soon as possible. On January 29, 2025, Houston Electric announced that a settlement agreement was reached with certain parties to the rate case filed on March 6, 2024, including the City of Houston and other regional municipalities. Subject to PUCT review and approval, the settlement is expected to result in approximately $50 million less annual revenue and an average decrease of approximately $1 a month for residential customers based on average usage of 1,000 kWh per month. A proposed order was issued on February 10, 2025. The parties must file corrections or exceptions to the proposed order by February 24, 2025.
Ohio Capital Expenditure Program (CEP). On March 1, 2024, CEOH filed an application with the PUCO for authority to modify its CEP rates and charges. The requested increase is approximately $3 million resulting in a proposed CEP rate for residential customers of $1.54 per month. Per the PUCO’s Opinion and Order in the 2018 general rate case, the CEP rate is capped at $1.50 per month for residential customers. CEOH requested deferral of the 2023 CEP revenue requirement above the CEP rate cap of approximately $155,000. CEOH filed a statement of resolution on July 30, 2024, indicating CEOH and PUCO staff agree to certain statements including: CEOH’s existing deferral authority has not expired and will continue uninterrupted, provided CEOH files its notice of intent for its base rate case prior to the new CEP Rider charges taking effect. PUCO issued a Finding & Order on August 21, 2024, finding that the parties’ resolution of the rate cap and deferral authority issues were reasonable. As discussed below, notice of intent for a base rate case was filed the following week.
Ohio Gas Rate Case. On August 27, 2024, CEOH filed a Notice of Intent with PUCO to begin the process of requesting an adjustment in natural gas base rates. CEOH filed its Application and Standard Filing Requirement in October 2024 and the related testimony in November 2024. The filing seeks a revenue requirement increase of approximately $100 million based on a requested return on equity of 10.4% and equity percentage of 45.87%. The need for a rate increase is primarily driven by the continuing investment in the safety and reliability of the natural gas system. A final order is expected no sooner than the first quarter of 2026.
The table below reflects significant applications pending or completed since the Registrants’ combined 2023 Form 10-K was filed with the SEC through the date of the filing of this Form 10-K:
Mechanism Annual Increase (1)
(in millions)
Filing
Date Effective Date Approval Date Additional Information
CenterPoint Energy and Houston Electric (PUCT)
DCRF
December 2023
April 2024
March 2024
Based on the net change in distribution invested capital since its last base rate proceeding of approximately $2.5 billion for the period January 1, 2019 through September 30, 2023, of which $672 million is incremental to the previous DCRF filing, for an incremental revenue increase of $86 million, adjusted for load growth. On February 5, 2024, Houston Electric notified the ALJ that the parties reached an agreement in principle on all issues in this proceeding and filed an agreed expedited motion for interim rates. On February 13, 2024, interim rates designed to collect $220 million ($73 million incremental) were approved by the ALJ, to be effective April 2024. A final order was issued by the PUCT March 7, 2024.
Rate Case
March 2024
TBD
TBD
See discussion above under Houston Electric Rate Case.
EECRF
May
March 2025
December 2024
The requested $65 million is comprised primarily of the following: 2025 program costs of $50 million; a credit of $0.5 million related to the over-recovery of 2023 program costs; the 2023 earned bonus of $15 million; and 2025 projected evaluation, measurement and verification costs of $0.5 million. On October 17, 2024, a unanimous settlement was filed for an adjusted total of $63 million, keeping the 2023 earned bonus of $15 million. A final order approving the settlement was issued on December 12, 2024.
TCOS
November 2024
January 2025
January 2025
Based on net change in invested capital of $517 million for the period July 2023 through September 2024. Notice of Approval was issued by PUCT January 13, 2025.
CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission)
Rate Case
October 2023
December 2024
June
See discussion above under Texas Gas Rate Case.
Tax Act Rider
August 2024
TBD
TBD
Resulting from the Texas Gas Rate Case, the first Tax Act Rider Calculation was filed on August 1, 2024 pursuant to Docket No. OS-23-00015513 to recover the effects of the Inflation Reduction Act (“Tax Act 2022”) and certain other tax-related costs for rates to become effective January 1, 2025. These effects include the return on the CAMT deferred tax asset (“DTA”) resulting from the Tax Act 2022, income tax credits resulting from the Tax Act 2022, and the return on the increment or decrement in the NOL DTA included in rate base and in the standard service base revenue requirement approved in the Texas Gas Rate Case. CERC believes its filing is consistent with the Tax Act Rider tariff approved in Docket No. OS-23-00015513. On October 1, 2024, certain parties filed comments disputing the application. Briefings were filed with an ALJ in November 2024. A hearing on the merits will be held on February 21, 2025.
GRIP
February 2025
TBD
TBD
Based on net change in invested capital of $446 million.
Mechanism Annual Increase (1)
(in millions)
Filing
Date Effective Date Approval Date Additional Information
CenterPoint Energy and CERC - Minnesota (MPUC)
CIP Financial Incentive
May
December 2024
November 2024
CIP Financial Incentive based on 2023 CIP program activity.
Rate Case
November 2023
TBD
TBD
See discussion above under Minnesota Gas Rate Case.
CenterPoint Energy and CERC - Louisiana (LPSC)
RSP
September/October 2023
June
April
Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, net of TCJA effects considered outside of the earnings band and completion of COVID-19 asset recovery, is $8 million based on a test year ended June 2023 and adjusted ROE of 3.67%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band and completion of COVID-19 asset recovery, is $5 million based on a test year ended June 2023 and adjusted ROE of 5.47%. The TCJA refund impact to North Louisiana and South Louisiana was $0.6 million and $0.4 million, respectively. South Louisiana interim rates were implemented on December 28, 2023, subject to refund. North Louisiana interim rates were implemented on January 29, 2024. Staff reports issued on January 31, 2024 recommended disallowances of $0.3 million and $0.2 million in North and South Louisiana, respectively. LPSC voted to approve the January 2024 staff reports on April 19, 2024. Implementation occurred in June 2024.
RSP
October 2024
TBD
TBD
Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, inclusive of TCJA effects considered outside of the earnings band, is $7 million based on a test year ended June 2024 and adjusted ROE of 5.56%. The South Louisiana increase, inclusive of TCJA effects considered outside of the earnings band, is $6 million based on a test year ended June 2024 and adjusted ROE of 5.96%. Interim rates, subject to refund, were implemented December 19, 2024.
CenterPoint Energy and CERC - Mississippi (MPSC)
RRA
May
September 2024
September 2024
Based on ROE of 10.263% with 100 basis points (+/-) earnings band. Revenue increase of approximately $11 million based on 2023 test year adjusted earned ROE of 5.11%. Interim increase of approximately $1.3 million implemented May 31, 2024. On September 5, 2024, MPSC approved a settlement revenue adjustment of $9.4 million.
CenterPoint Energy - Indiana South - Gas (IURC)
CSIA
April
August
July
Requested an increase of $35 million to rate base, which reflects approximately $3.6 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $0.03 million annually. The final IURC order was issued July 31, 2024, approving CSIA rates as proposed effective August 1, 2024.
CSIA
October 2024
February 2025
January 2025
Requested an increase of $18 million to rate base, which reflects approximately $2.4 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $(1.0) million annually. The final IURC order was issued January 29, 2025 approving rates as filed with the correction filing effective February 1, 2025.
Mechanism Annual Increase (1)
(in millions)
Filing
Date Effective Date Approval Date Additional Information
CenterPoint Energy and CERC - Indiana North - Gas (IURC)
CSIA
9 April
August 2024
July
Requested an increase of $97 million to rate base, which reflects approximately $9.4 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. The final IURC Order was issued July 31, 2024, approving CSIA rates as proposed effective August 1, 2024.
CSIA
October 2024
February 2025
January 2025
Requested an increase of $84 million to rate base, which reflects approximately $11.0 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $(3.0) million annually. The final IURC order was issued January 29, 2025, approving rates as filed with the correction filing effective February 1, 2025.
CenterPoint Energy and CERC - Ohio - Gas (PUCO)
CEP
3 March
September
August 2024
See discussion above under Ohio Capital Expenditure Program.
DRR
May
September 2024
August 2024
Requested an increase of $77 million to rate base for investments made in 2023, which reflects a $12 million annual increase in current revenues. A change in (over)/under-recovery variance of $0.8 million annually is also included in rates. PUCO Opinion & Order was issued August 21, 2024, approving DRR rates as proposed. Revised rates became effective September 1, 2024.
Rate Case
October 2024
TBD
TBD
See discussion above under Ohio Gas Rate Case.
CenterPoint Energy - Indiana Electric (IURC)
Rate Case
80 December 2023
February 2025
February 2025
See discussion above under Indiana Electric Rate Case.
TDSIC
5 February 2024
May
May
Requested an increase of $36 million to rate base, which reflects a $5 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until next rate case. An order approving the request was issued on May 17, 2024 and was effective May 16, 2024.
CECA
- February 2024
May
June
Requested a decrease of $1 million to rate base, which reflects no change in current revenues. The mechanism also includes a change in (over)/under-recovery variance of $0.1 million. The final order was issued May 29, 2024, approving rates effective June 1, 2024.
ECA
6 May
August 2024
August 2024
Requested an increase of $48 million to rate base, which reflects a $6 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until next rate case. The mechanism also includes a reduction in the under-recovery variance of $1 million. The OUCC filed testimony on July 1, 2024 recommending approval. A final order approving the request was issued on August 28, 2024.
TDSIC
5 August 2024
November 2024
November 2024
Requested an increase of $30 million to rate base, which reflects a $5 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The final order was issued on November 27, 2024 approving rates effective November 28, 2024.
(1)Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates.
Inflation Reduction Act (IRA)
On August 16, 2022, the IRA was signed into law. The law extends or creates tax-related energy incentives for solar, wind and alternative clean energy sources, implements, subject to certain exceptions, a 1% tax on share repurchases after December 31, 2022, and implements a 15% CAMT based on the adjusted financial statement income of certain large corporations. Corporations are entitled to a CAMT credit to the extent CAMT liability exceeds regular tax liability, which can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT. The Registrants will owe CAMT in excess of their regular tax liability beginning in 2024. As a result, the Registrants may experience a temporary increase in federal cash tax liability due to this provision beginning in 2024. On September 12, 2024, the IRS issued proposed regulations addressing the application of the CAMT. The proposed regulations offer guidance for computing an entity’s adjusted financial statement income, in addition to addressing other provisions of the CAMT. At this time, the Company does not anticipate changes to the applicability of CAMT to the Registrants as a result of the proposed regulations. For more information regarding changes in federal income tax laws and regulations and our related risks, see Part I, Item 1A. “Risk Factors - Risk Factors Affecting Regulatory, Environmental and Legal Risks - We may be significantly affected by changes in federal income tax laws and regulations...”
Greenhouse Gas Regulation and Compliance (CenterPoint Energy)
CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of reducing the consumption of natural gas. Additionally, the Methane Emissions Reduction Program established by the IRA and the new regulations published by the EPA on March 8, 2024 targeting reductions in methane emissions, may increase costs related to production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within their respective service territories. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services. Further, requirements and/or incentives to reduce energy consumption by certain specified dates in the Registrants’ respective service areas could have a significant impact on CenterPoint Energy and its operations. Further, our third-party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact CenterPoint Energy’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to CenterPoint Energy. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to benefit CenterPoint Energy and CERC and their natural gas-related businesses. At this time, however, we cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Registrants’ businesses. Additionally, the Registrants continue to evaluate the impact of the final rules adopted by the SEC on March 6, 2024 regarding disclosure of certain climate-related information in registration statements and annual reports, for which implementation is subject to ongoing voluntary delay by the SEC, on their respective consolidated financial statements and related disclosures.
Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain; nevertheless, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. CenterPoint Energy will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, CenterPoint Energy does not purchase carbon credits. In connection with its net zero emissions goals, CenterPoint Energy is expected to purchase carbon credits in the future; however, CenterPoint Energy does not currently expect the number of credits, or cost for those credits, to be material. For more information on greenhouse gas and climate-change regulation and compliance, see “Business-Environmental Matters” in Item 1 of Part I of this report.
Climate Change Trends and Uncertainties
As a result of increased attention regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Registrants’ services. As these technologies likely become more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Registrants’ systems and
services, which may result in, among other things, Indiana Electric’s generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on CenterPoint Energy’s electric generation and natural gas businesses. For example, because Indiana Electric currently relies on coal for a portion of its generation capacity, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Conversely, demand for the Registrants’ services may increase as a result of customer changes in response to climate change. For example, the expected expansion of energy export facilities, including hydrogen facilities, and electrification of industrial processes and transport and logistics, among others, in our service territories could lead to an increase in demand for electricity, resulting in increased usage of CenterPoint Energy’s systems and services. Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation.
To address these developments, CenterPoint Energy announced its net zero emission goals for Scope 1 and certain Scope 2 emissions by 2035 and a 20-30% reduction in certain Scope 3 emissions by 2035 as compared to 2021 levels. Indiana Electric’s 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation. Indiana Electric continues to execute on its 2019/2020 IRP and has received initial approvals for 626 MWs of the 700-1,000 MWs of solar generation and 200 MWs of the 300 MWs of wind generation identified within Indiana Electric’s 2019/2020 IRP through a combination of BTAs and PPAs. Additionally, as reflected in its 10-year capital plan announced in September 2021, CenterPoint Energy anticipates spending over $3 billion in cleaner energy investments and enablement, which may be used to support, among other things, renewable energy generation. CenterPoint Energy believes its planned investments in renewable energy generation and corresponding planned reduction in its Scope 1 and certain Scope 2 emissions as part of its net zero emissions goals, as well as its planned reduction in Scope 3 emissions by 20-30% by 2035 as compared to 2021 levels, support global efforts to reduce the impacts of climate change. Indiana Electric has conducted a new IRP, which was submitted to the IURC in May 2023, to identify an appropriate generation resource portfolio to satisfy the needs of its customers and comply with environmental regulations. The proposed preferred portfolio is the second evolution to the generation transition plan to move away from coal-fired generation to a more sustainable portfolio of resources. Under the proposed preferred portfolio, Indiana Electric plans to convert its last remaining coal unit to natural gas and to add a significant amount of additional renewable resources through 2033. Indiana Electric has since received approval for 147 MWs of wind generation facilities identified within Indiana Electric’s 2022/2023 IRP through a PPA. For more information regarding CenterPoint Energy’s net zero and GHG emissions reduction goals and the risks associated with them, see Part I, Item 1A. “Risk Factors - Risk Factors Affecting Regulatory, Environmental and Legal Risks - CenterPoint Energy is subject to operational and financial risks...” For more information on Indiana Electric’s IRP and associated risks, see Part I, Item 1A. “Risk Factors - Risk Factors Affecting Regulatory, Environmental and Legal Risks - Indiana Electric’s execution of its generation transition plan...”
To the extent climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales. On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity used for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes, floods, microbursts, severe winter weather conditions, including ice storms, wildfires, thunderstorms, high winds, hail, derecho events, or extreme temperatures, including such storms as the February 2021 Winter Storm Event, the May 2024 Storm Events and Hurricane Beryl. Since many of the Registrants’ facilities are located along or near the Texas Gulf Coast, increased or more severe weather events could increase costs to repair damaged facilities and restore service to customers. CenterPoint Energy’s current 10-year capital plan includes capital expenditures to maintain reliability and safety and increase resiliency of its systems as climate change may result in more frequent significant weather events. Houston Electric does not own or operate any electric generation facilities other than, since September 2021, its operation of TEEEF. Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. To the extent adverse weather conditions affect the Registrants’ suppliers, results from their energy delivery businesses may suffer. For example, in Texas, the February 2021 Winter Storm Event caused an electricity generation shortage that was severely disruptive to Houston Electric’s service territory and the wholesale generation market and also caused a reduction in available natural gas capacity. Additionally, the May 2024 Storm Events and Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in electric service interruptions peaking at an estimated 922,000 customers and more than 2.1 million customers, respectively. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted. Further, as the
intensity and frequency of significant weather events continues, it may impact our ability to secure cost-efficient insurance. For more information regarding risks relating to climate change and other weather and natural disaster impacts, see Part I, Item 1A. “Risk Factors - Risk Factors Affecting Regulatory, Environmental and Legal Risks - Climate change and other weather and natural disaster impacts could...”
Other Matters
Credit Facilities
The Registrants may draw on their respective revolving credit facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop CenterPoint Energy’s and CERC’s commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to the Registrants’ revolving credit facilities, see Note 12 to the consolidated financial statements.
Based on the consolidated debt to capitalization covenant in the Registrants’ revolving credit facilities, the Registrants would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated approximately $4.0 billion as of December 31, 2024.
As of February 10, 2025, the Registrants had the following revolving credit facilities and utilization of such facilities:
Amount Utilized as of February 10, 2025
Registrant Size of Facility Loans Letters of Credit Commercial Paper Weighted Average Interest Rate Termination Date
(in millions)
CenterPoint Energy $ 2,400 $ - $ - $ 737 4.50% December 6, 2028
CenterPoint Energy (1) 250 - - - -% December 6, 2028
Houston Electric 300 - - - -% December 6, 2028
CERC 1,050 - - 497 4.51% December 6, 2028
Total $ 4,000 $ - $ - $ 1,234
(1)This credit facility was issued by SIGECO.
Borrowings under each of the revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower makes representations prior to borrowing as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the revolving credit facilities, the spread to SOFR and the commitment fees fluctuate based on the borrower’s credit rating. Each of the Registrant’s credit facilities provide for a mechanism to replace SOFR with possible alternative benchmarks upon certain benchmark replacement events. The borrowers are currently in compliance with the various business and financial covenants in the four revolving credit facilities.
Debt Transactions
For detailed information about the Registrants’ debt transactions in 2024, see Note 12 to the consolidated financial statements.
Securities Registered with the SEC
On May 17, 2023, the Registrants filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on May 17, 2026. For information related to the Registrants’ debt issuances in 2024, see Note 12 to the consolidated financial statements.
Temporary Investments
As of February 10, 2025, the Registrants had no temporary investments.
Money Pool
The Registrants participate in a money pool through which they and certain of their subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the CenterPoint Energy money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The net funding requirements of the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of CERC’s commercial paper. The money pool may not provide sufficient funds to meet the Registrants’ cash needs.
The table below summarizes CenterPoint Energy money pool activity by Registrant as of February 10, 2025:
Weighted Average Interest Rate Houston Electric CERC
(in millions)
Money pool borrowings
4.56% $ 58 $ -
Impact on Liquidity of a Downgrade in Credit Ratings
The interest rate on borrowings under the Registrants’ credit facilities is based on their respective credit ratings. As of February 10, 2025, Moody’s, S&P and Fitch had assigned the following credit ratings to the borrowers:
Moody’s S&P Fitch
Registrant Borrower/Instrument Rating Outlook (1) Rating Outlook (2) Rating Outlook (3)
CenterPoint Energy CenterPoint Energy Senior Unsecured Debt Baa2 Negative BBB Negative BBB Negative
CenterPoint Energy Vectren Corp. Issuer Rating n/a Negative BBB+ Negative n/a n/a
CenterPoint Energy SIGECO Senior Secured Debt A1 Stable A Negative n/a n/a
Houston Electric Houston Electric Senior Secured Debt A2 Negative A Negative A Negative
CERC CERC Corp. Senior Unsecured Debt A3 Stable BBB+ Negative A- Negative
CERC Indiana Gas Senior Unsecured Debt n/a n/a BBB+ Negative n/a n/a
(1)A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term.
(2)An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.
(3)A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.
The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have a material adverse impact on the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies.
A decline in credit ratings could increase borrowing costs under the Registrants’ revolving credit facilities. If the Registrants’ credit ratings had been downgraded one notch by S&P and Moody’s from the ratings that existed as of December 31, 2024, the impact on the borrowing costs under the four revolving credit facilities would have been insignificant. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas reportable segments.
Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels,
CERC might need to provide cash or other collateral of as much as $159 million as of December 31, 2024. The amount of collateral will depend on seasonal variations in transportation levels.
ZENS and Securities Related to ZENS (CenterPoint Energy)
If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought CenterPoint Energy’s liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on December 31, 2024, deferred taxes of approximately $802 million would have been payable in 2024. If all the ZENS-Related Securities had been sold on December 31, 2024, capital gains taxes of approximately $84 million would have been payable in 2024 based on 2024 tax rates in effect. For additional information about ZENS, see Note 10 to the consolidated financial statements.
Cross Defaults
Under the Registrants’ respective revolving credit facilities and any term loan agreements (in each case, other than SIGECO), a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by the borrower or any of their respective significant subsidiaries will cause a default under such borrower’s respective credit facility or term loan agreement. Under SIGECO’s revolving credit facility, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specific types of obligations (including guarantees) exceeding $75 million by SIGECO or any of its significant subsidiaries will cause a default under SIGECO’s credit facility. A default by CenterPoint Energy would not trigger a default under its subsidiaries’ debt instruments or revolving credit facilities.
Possible Acquisitions, Divestitures and Joint Ventures
From time to time, the Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. The Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to the Registrants at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions. CenterPoint Energy has increased its planned capital expenditures in its Electric and Natural Gas businesses multiple times over the recent years to support rate base growth and may continue to do so in the future. The Registrants may continue to explore asset sales as a means to efficiently finance a portion of their increased capital expenditures in the future, subject to the considerations listed above. For further information, see Note 4 to the consolidated financial statements.
On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 4 to the consolidated financial statements.
Collection of Receivables from REPs (CenterPoint Energy and Houston Electric)
Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, weather events, such as the February 2021 Winter Storm Event, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows. In the event of a REP’s default, Houston Electric’s tariff provides a number of remedies,
including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations and claims might be made against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.
Other Factors that Could Affect Cash Requirements
In addition to the above factors, the Registrants’ liquidity and capital resources could also be negatively affected by:
•cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas reportable segment;
•acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased natural gas prices, and concentration of natural gas suppliers (CenterPoint Energy and CERC);
•increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC);
•increases in interest expense in connection with debt refinancings and borrowings under credit facilities or term loans or the use of alternative sources of financings, including financings due to the May 2024 Storm Events and Hurricane Beryl;
•various legislative or regulatory actions, including such actions in response to the May 2024 Storm Events and Hurricane Beryl;
•incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy);
•the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric;
•slower customer payments and increased write-offs of receivables due to higher natural gas prices, changing economic conditions, public health threats or severe weather events, such as the May 2024 Storm Events and Hurricane Beryl (CenterPoint Energy and CERC);
•the satisfaction of any obligations pursuant to guarantees;
•the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl;
•contributions to pension and postretirement benefit plans;
•recovery of any losses under applicable insurance policies;
•restoration costs and revenue losses resulting from future natural disasters such as hurricanes or other severe weather events and the timing of and amounts sought for recovery of such restoration costs; and
•various other risks identified in “Risk Factors” in Part I, Item 1A of this report.
Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money
Certain provisions in certain note purchase agreements relating to debt issued by CERC have the effect of restricting the amount of secured debt issued by CERC and debt issued by subsidiaries of CERC Corp. Additionally, Houston Electric and SIGECO are limited in the amount of mortgage bonds they can issue by the General Mortgage and SIGECO’s mortgage indenture, respectively. For information about the total debt to capitalization financial covenants in the Registrants’ and SIGECO’s revolving credit facilities, see Note 12 to the consolidated financial statements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of the Registrants’ financial statements in conformity with GAAP requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on the Registrants’ financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. Our management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates
have been reviewed and discussed with the Audit Committee of CenterPoint Energy’s Board of Directors. For a complete discussion of the Registrants’ significant accounting policies, see Note 2 to the consolidated financial statements.
Accounting for Rate Regulation
Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. CenterPoint Energy, for its Electric and Natural Gas reportable segments, Houston Electric and CERC apply this accounting guidance. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals. If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Registrants would be required to write off or write down these regulatory assets and liabilities. For further detail on the Registrants’ regulatory assets and liabilities, see Note 7 to the consolidated financial statements.
Impairment of Long-Lived Assets, Including Goodwill
The Registrants review the carrying value of long-lived assets, including goodwill, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually, goodwill is tested for impairment as required by accounting guidance for goodwill. Unforeseen events, changes in market conditions, and probable regulatory disallowances, where applicable, could have a material effect on the value of long-lived assets, including goodwill, future cash flows, interest rate, and regulatory matters, and could result in an impairment charge. The Registrants recorded no impairments to long-lived assets, including goodwill during 2024, 2023 and 2022.
Fair value is the amount at which an asset, liability or business could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value could be different using different estimates and assumptions in these valuation techniques.
Fair value measurements require significant judgment and unobservable inputs, including (i) projected timing and amount of future cash flows, which factor in planned growth initiatives, (ii) the regulatory environment, as applicable, and (iii) discount rates reflecting risk inherent in the future market prices. Determining the discount rates for the businesses that are not rate-regulated, such as for Energy Systems Group prior to the sale in June 2023, requires the estimation of the appropriate company-specific risk premiums for such businesses based on evaluation of industry and entity-specific risks, which includes expectations about future market or economic conditions existing on the date of the impairment test. Changes in these assumptions could have a significant impact on results of the impairment tests.
Annual Goodwill Impairment Test
CenterPoint Energy and CERC completed their 2024 annual goodwill impairment test during the third quarter of 2024 and determined, based on a qualitative assessment, that no goodwill impairment charge was required for any reporting unit. No qualitative factors were present that indicated impairment of CenterPoint Energy or CERC reporting units.
Although no goodwill impairment resulted from the 2024 annual test, an interim goodwill impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, if CenterPoint Energy’s market capitalization falls below book value for an extended period of time, or events affecting a reporting unit such as a contemplated disposal of all or part of a reporting unit.
Assets Held for Sale
Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell, and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale, or the disposal group, at the lower of their carrying value or their estimated fair value less cost to sell. If the disposal group reflects a component of a reporting unit and meets the definition of a business,
the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business.
As described further in Note 4 to the consolidated financial statements, certain assets and liabilities of the Louisiana and Mississippi natural gas LDC businesses met the held for sale criteria and the goodwill attributable to these businesses as of December 31, 2024 was $217 million and $122 million for CenterPoint Energy and CERC, respectively.
Accounting for Securitization of Coal Generation Facility Retirements
Accounting guidance for rate regulated long-lived asset abandonment requires that the carrying value of an operating asset or an asset under construction is removed from property, plant and equipment when it becomes probable that the asset will be abandoned. The Registrants recognize a loss on abandonment when they conclude it is probable the cost will not be recovered in future rates. When the Registrants conclude it is probable that costs will be recovered in future rates, a regulatory asset is recognized. The portion of property, plant and equipment that will remain used and useful until abandonment and recovered through depreciation expense in rates will continue to be classified as property, plant and equipment until the asset is abandoned. The Registrants evaluate if an adjustment to the estimated life of the asset and, accordingly, the rate of depreciation, is required to recover the asset while it is still providing service. Determining probability of abandonment or probability of recovery requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals.
In connection with the securitization financing of qualified costs in the second quarter of 2023 associated with the completed retirement of SIGECO’s A.B. Brown coal generation facilities, CenterPoint Energy evaluated the VIE consisting of the SIGECO Securitization Subsidiary, a wholly-owned, bankruptcy-remote, special purpose entity, for possible consolidation, including review of qualitative factors such as the power to direct the activities of the VIE and the obligation to absorb losses of the VIE. CenterPoint Energy has the power to direct the significant activities of the VIE and is most closely associated with the VIE as compared to other interests held by the holders of the SIGECO Securitization Bonds. CenterPoint Energy is, therefore, considered the primary beneficiary and consolidated the VIE.
For purposes of reporting cash flows, the Registrants consider cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the SIGECO Securitization Subsidiary solely to support servicing the SIGECO Securitization Bonds as of December 31, 2024 are reflected on CenterPoint Energy’s Consolidated Balance Sheet.
In connection with the issuance of the SIGECO Securitization Bonds, CenterPoint Energy was required to establish a restricted cash account to collateralize the SIGECO Securitization Bonds that were issued in the financing transaction. The restricted cash account is not available for withdrawal until the maturity of the SIGECO Securitization Bonds and is not included in cash and cash equivalents.
Unbilled Revenues
Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month either electronically through AMS meter communications or manual readings. At the end of each month, deliveries to non-AMS customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Information regarding deliveries to AMS customers after the last billing is obtained from actual AMS meter usage data. Unbilled electricity delivery revenue is estimated each month based on actual AMS meter data, daily supply volumes and applicable rates. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Employee Benefit Plans
CenterPoint Energy sponsors pension and other retirement plans in various forms covering all employees who meet eligibility requirements. CenterPoint Energy uses several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to its plans. These factors include assumptions about the discount rate, expected
return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, CenterPoint Energy’s actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension and other retirement plans expense recorded. Read “- Other Significant Matters - Pension Plans” for further discussion.
NEW ACCOUNTING PRONOUNCEMENTS
See Note 2(q) to the consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect the Registrants.
OTHER SIGNIFICANT MATTERS
Pension Plans (CenterPoint Energy). As discussed in Note 8(b) to the consolidated financial statements, CenterPoint Energy maintains non-contributory qualified defined benefit pension plans covering eligible employees. Employer contributions for the qualified plans are based on actuarial computations that establish the minimum contribution required under ERISA and the maximum deductible contribution for income tax purposes.
Under the terms of CenterPoint Energy’s pension plans, it reserves the right to change, modify or terminate the plan. CenterPoint Energy’s funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA.
Additionally, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans which allow participants to receive the benefits to which they would have been entitled under the non-contributory qualified pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated.
CenterPoint Energy’s funding requirements and employer contributions for the years ended December 31, 2024, 2023 and 2022 were as follows:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy (in millions)
Minimum funding requirements for qualified pension plans $ 23 $ - $ -
Employer contributions to the qualified pension plans 23 24 27
Employer contributions to the non-qualified pension plans
7 8 8
CenterPoint Energy expects to make contributions of approximately $105 million and $7 million to the qualified and non-qualified pension plans in 2025, respectively.
Changes in pension obligations and plan assets may not be immediately recognized as pension expense in CenterPoint Energy’s Statements of Consolidated Income, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants.
As the sponsor of a plan, CenterPoint Energy is required to (a) recognize on its Consolidated Balance Sheet an asset for the plan’s over-funded status or a liability for the plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of the fiscal year and (c) recognize changes in the funded status of the plans in the year that changes occur through adjustments to other comprehensive income and, when related to its rate-regulated utilities with recoverability of cost, to regulatory assets.
The projected benefit obligation for all defined benefit pension plans was $1.5 billion as of December 31, 2024 and 2023, respectively. The impacts resulting from increases in discount rates were offset by the changes in demographic and expected versus actual returns on assets.
As of December 31, 2024, the projected benefit obligation exceeded the market value of plan assets of CenterPoint Energy’s pension plans by $345 million. Changes in interest rates or the market values of the securities held by the plan during
a year could materially, positively or negatively, change the funded status and affect the level of pension expense and required contributions at the next remeasurement.
Houston Electric and CERC participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. Pension cost by Registrant was as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Pension cost $ 51 $ 23 $ 18 $ 53 $ 27 $ 19 $ 172 $ 59 $ 88
The calculation of pension cost and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.
As of December 31, 2024, CenterPoint Energy’s qualified pension plans had an expected long-term rate of return on plan assets of 7.00%, which is 50 basis points higher than the 6.50% rate assumed as of December 31, 2023. The expected rate of return assumption was developed using the targeted asset allocation of our plans and the expected return for each asset class. CenterPoint Energy regularly reviews its actual asset allocation and periodically rebalances plan assets to reduce volatility and better match plan assets and liabilities.
As of December 31, 2024, the projected benefit obligation was calculated assuming a discount rate of 5.60%, which is 65 basis points higher than the 4.95% discount rate assumed as of December 31, 2023 attributed primarily to rising interest rates. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of CenterPoint Energy’s plans.
CenterPoint Energy’s actuarially determined pension and other postemployment cost for 2024 and 2023 that is greater or less than the amounts being recovered through rates in the majority of Texas jurisdictions is deferred as a regulatory asset or liability, respectively. Pension cost for 2025, including the non-qualified benefit restoration plan, is estimated to be $49 million before applicable regulatory deferrals and capitalization, based on an expected return on plan assets of 7.00% and a discount rate of 5.60% as of December 31, 2024. If the expected return assumption were lowered by 50 basis points from 7.00% to 6.50%, the 2025 pension cost would increase by approximately $6 million.
As of December 31, 2024, the pension plans projected benefit obligation, including the unfunded non-qualified pension plans, exceeded plan assets by $345 million. If the discount rate were lowered by 50 basis points from 5.60% to 5.10%, CenterPoint Energy’s projected benefit obligation would increase by approximately $60 million and its 2025 pension cost would decrease by approximately $2 million. The expected reduction in pension cost due to the decrease in discount rate is a result of the expected correlation between the reduced interest rate and appreciation of fixed income assets in pension plans with significantly more fixed income instruments than equity instruments. In addition, the assumption change would impact CenterPoint Energy’s Consolidated Balance Sheets by increasing the regulatory asset recorded as of December 31, 2024 by $54 million and would result in an incremental charge to comprehensive income in 2024 of $5 million, net of tax of $1 million, due to the increase in the projected benefit obligation.
Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plans will impact CenterPoint Energy’s future pension expense and liabilities. CenterPoint Energy cannot predict with certainty what these factors will be in the future.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Impact of Changes in Interest Rates, Equity Prices and Energy Commodity Prices
The Registrants are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in the Registrants’ consolidated financial statements. Most of the revenues and income from the Registrants’ business activities are affected by market risks. Categories of market risk include exposure to interest rates, equity prices and commodity prices through non-trading activities. A description of each market risk is set forth below:
•Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates;
•Equity price risk results from exposures to changes in prices of individual equity securities (CenterPoint Energy); and
•Commodity price risk results from exposures to price volatilities of commodities, such as natural gas, NGLs and other energy commodities (CenterPoint Energy).
Management has established comprehensive risk management policies to monitor and manage these market risks.
Interest Rate Risk
As of December 31, 2024, the Registrants had outstanding long-term debt and lease obligations and CenterPoint Energy had obligations under its ZENS that subject them to the risk of loss associated with movements in market interest rates. The Registrants seek to manage interest rate exposure by monitoring the effects of changes in market interest rates and using a combination of fixed and variable rate debt. Additionally, interest rate swaps are used to mitigate interest rate exposure when deemed appropriate. See Note 7 to the Interim Condensed Financial Statements.
CenterPoint Energy’s floating rate obligations aggregated $1.5 billion and $1.9 billion as of December 31, 2024 and 2023, respectively. If the floating interest rates were to increase by 100 basis points from December 31, 2024 rates, CenterPoint Energy’s combined interest expense would increase by approximately $15 million annually.
Houston Electric’s floating rate obligations aggregated $500 million as of December 31, 2024, which mature on December 24, 2025. Houston Electric had no floating rate notes as of December 31, 2023.
CERC’s floating rate obligations aggregated $599 million and $484 million as of December 31, 2024 and 2023, respectively. If the floating interest rates were to increase by 100 basis points from December 31, 2024 rates, CERC’s combined interest expense would increase by approximately $6 million annually. CERC has no floating rate notes maturing in 2025.
As of December 31, 2024 and 2023, CenterPoint Energy had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $19.7 billion and $16.9 billion, respectively, in principal amount and having a fair value of $18.4 billion and $16.1 billion, respectively. Because these instruments are fixed-rate, they do not expose CenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $792 million if interest rates were to decline by 10% from their levels as of December 31, 2024.
As of December 31, 2024 and 2023, Houston Electric had outstanding fixed-rate debt aggregating $8.4 billion and $7.7 billion, respectively, in principal amount and having a fair value of approximately $7.3 billion and $7 billion, respectively. Because these instruments are fixed-rate, they do not expose Houston Electric to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $398 million if interest rates were to decline by 10% from their levels as of December 31, 2024. Houston Electric has no fixed-rate general mortgage bonds maturing in 2025.
As of December 31, 2024 and 2023, CERC had outstanding fixed-rate debt aggregating $4.6 billion and $4.2 billion, respectively, in principal amount and having a fair value of $4.5 billion and $4.2 billion, respectively. Because these instruments are fixed-rate, they do not expose CERC to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $160 million if interest rates were to decline by 10% from their levels at December 31, 2024. CERC has $10 million fixed-rate senior notes maturing in 2025.
In general, such an increase in fair value previously described would impact earnings and cash flows only if the Registrants were to reacquire all or a portion of these instruments in the open market prior to their maturity.
The ZENS obligation is bifurcated into a debt component and a derivative component. The debt component of $2 million at December 31, 2024 was a fixed-rate obligation and, therefore, did not expose CenterPoint Energy to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by less than $1 million if interest rates were to decline by 10% from levels at December 31, 2024. Changes in the fair value of the derivative component, a $619 million recorded liability at December 31, 2024, are recorded in CenterPoint Energy’s Statements of Consolidated Income and, therefore, it is exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from December 31, 2024 levels, the fair value of the derivative component liability would decrease by approximately $1 million, which would be recorded as a gain on indexed securities in CenterPoint Energy’s Statements of Consolidated Income.
Equity Market Value Risk (CenterPoint Energy)
CenterPoint Energy is exposed to equity market value risk through its ownership of 10.2 million shares of AT&T Common, 0.9 million shares of Charter Common and 2.5 million shares of WBD Common, which CenterPoint Energy holds to facilitate its ability to meet its obligations under the ZENS. See Note 10 to the consolidated financial statements for a discussion of CenterPoint Energy’s ZENS obligation. Changes in the fair value of the ZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS. A decrease of 10% from the December 31, 2024 aggregate market value of these shares would result in a net loss of less than $1 million, which would be recorded on a gross basis as both a gain on indexed debt securities and as a loss on equity securities in CenterPoint Energy’s Statements of Consolidated Income.
Commodity Price Risk From Non-Trading Activities (CenterPoint Energy and CERC)
CenterPoint Energy’s regulated operations are exposed to commodity price risk during severe weather events, such as hurricanes, tornadoes and severe winter weather conditions. Severe weather events can increase commodity prices related to natural gas, coal and purchased power, which may increase our costs of providing service, and those costs may not be recoverable in rates. Recovery of cost increases driven by rising commodity prices during severe weather events could be resisted by our regulators and our regulators might attempt to deny or defer timely recovery of those costs.
However, CenterPoint Energy’s and CERC’s regulated operations in Indiana have limited exposure to commodity price risk for transactions involving purchases and sales of natural gas, coal and purchased power for the benefit of retail customers due to current state regulations, which, subject to compliance with those regulations, allow for recovery of the cost of such purchases through natural gas and fuel cost adjustment mechanisms. CenterPoint Energy’s and CERC’s utility natural gas operations in Indiana have regulatory authority to lock in pricing for up to 50% of annual natural gas purchases using arrangements with an original term of up to 10 years. This authority has been utilized to secure fixed price natural gas using both physical purchases and financial derivatives.
Although CenterPoint Energy’s and CERC’s regulated operations are exposed to limited commodity price risk, natural gas and coal prices have other effects on working capital requirements, interest costs, and some level of price-sensitivity in volumes sold or delivered. Constructive regulatory orders, such as those authorizing lost margin recovery, other innovative rate designs and recovery of unaccounted for natural gas and other natural gas-related expenses, also mitigate the effect natural gas costs may have on CenterPoint Energy’s financial condition. In 2008, the PUCO approved an exit of the merchant function in CenterPoint Energy’s and CERC’s Ohio natural gas service territory, allowing Ohio customers to purchase substantially all natural gas directly from retail marketers rather than from CenterPoint Energy or CERC.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
CenterPoint Energy, Inc. and Subsidiaries
Report of Independent Registered Public Accounting Firm
Statements of Consolidated Income
Statements of Consolidated Comprehensive Income
Consolidated Balance Sheets
Statements of Consolidated Cash Flows
Statements of Consolidated Changes in Equity
CenterPoint Energy Houston Electric, LLC and Subsidiaries
Report of Independent Registered Public Accounting Firm 101
Statements of Consolidated Income 103
Statements of Consolidated Comprehensive Income
Consolidated Balance Sheets 105
Statements of Consolidated Cash Flows 107
Statements of Consolidated Changes in Equity 108
CenterPoint Energy Resources Corp. and Subsidiaries
Report of Independent Registered Public Accounting Firm 109
Statements of Consolidated Income 111
Statements of Consolidated Comprehensive Income 112
Consolidated Balance Sheets 113
Statements of Consolidated Cash Flows 115
Statements of Consolidated Changes in Equity 116
Combined Notes to Consolidated Financial Statements
(1) Background
(2) Summary of Significant Accounting Policies
(3) Property, Plant and Equipment
(4) Held for Sale and Divestitures
(5) Revenue Recognition
(6) Goodwill 129
(7) Regulatory Matters
(8) Stock-Based Incentive Compensation Plans and Employee Benefit Plans
(9) Fair Value Measurements
(10) Equity Securities and Indexed Debt Securities (ZENS)
(11) Equity
(12) Short-term Borrowings and Long-term Debt
(13) Income Taxes
(14) Commitments and Contingencies
(15) Earnings Per Share (CenterPoint Energy)
(16) Reportable Segments
(17) Supplemental Disclosure of Cash Flow and Balance Sheet
(18) Related Party Transactions (Houston electric and CERC)
(19) Leases
(20) Subsequent Events
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of CenterPoint Energy, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 20, 2025, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements - Refer to Note 7 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. The impacts of accounting for the economics of rate regulation are pervasive to the financial statements and disclosures.
The Company’s rates are subject to regulatory rate-setting processes by the Commissions. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered in rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions
to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.
We identified rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory actions on the financial statements. Management’s judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company and (3) refunds to customers. Given that certain of management’s accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential uncertainty of decisions by the Commissions included the following, among others:
•We evaluated the Company’s disclosures related to the effects of rate regulation by testing certain recorded balances and evaluating regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 20, 2025
We have served as the Company's auditor since 1932.
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
2024 2023 2022
(in millions, except per share amounts)
Revenues:
Utility revenues $ 8,589 $ 8,524 $ 9,018
Non-utility revenues 54 172 303
Total 8,643 8,696 9,321
Expenses:
Utility natural gas, fuel and purchased power 1,715 2,061 2,887
Non-utility cost of revenues, including natural gas 3 99 204
Operation and maintenance 2,949 2,850 2,833
Depreciation and amortization 1,439 1,401 1,288
Taxes other than income taxes 547 525 543
Total 6,653 6,936 7,755
Operating Income 1,990 1,760 1,566
Other Income (Expense):
Gain (loss) on equity securities 20 31 (227)
Gain (loss) on indexed debt securities (14) (27) 325
Gain (loss) on sale - (13) 303
Interest expense and other finance charges (818) (684) (511)
Interest expense on Securitization Bonds (20) (17) (13)
Other income (expense), net 56 37 (26)
Total (776) (673) (149)
Income Before Income Taxes
1,214 1,087 1,417
Income tax expense 195 170 360
Net Income 1,019 917 1,057
Income allocated to preferred shareholders - 50 49
Income Available to Common Shareholders $ 1,019 $ 867 $ 1,008
Basic Earnings Per Common Share $ 1.58 $ 1.37 $ 1.60
Diluted Earnings Per Common Share $ 1.58 $ 1.37 $ 1.59
Weighted Average Common Shares Outstanding, Basic 643 631 629
Weighted Average Common Shares Outstanding, Diluted 644 633 632
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
2024 2023 2022
(in millions)
Net income
$ 1,019 $ 917 $ 1,057
Other comprehensive income (loss):
Adjustment to pension and other postemployment plans (net of tax expense (benefit) of $4, ($1) and $2, respectively)
15 (5) 32
Net deferred gain from cash flow hedges (net of tax of $-0-, $-0- and $-0-)
4 1 -
Reclassification of deferred (gain) loss from cash flow hedges realized in net income (net of tax of $-0-, $-0- and $-0-)
(1) - 1
Total 18 (4) 33
Comprehensive income 1,037 913 $ 1,090
Income allocated to preferred shareholders - 50 49
Comprehensive income available to common shareholders $ 1,037 $ 863 $ 1,041
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2024 December 31, 2023
(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($21 and $90 related to VIEs, respectively)
$ 24 $ 90
Investment in equity securities 561 541
Accounts receivable ($2 and $21 related to VIEs, respectively), less allowance for credit losses of $28 and $27, respectively
717 710
Accrued unbilled revenues ($2 and $2 related to VIEs, respectively), less allowance for credit losses of $2 and $2, respectively
521 516
Natural gas and coal inventory 173 197
Materials and supplies 541 573
Taxes receivable 121 94
Current assets held for sale
1,361 -
Regulatory assets 239 161
Prepaid expenses and other current assets ($2 and $15 related to VIEs, respectively)
123 145
Total current assets 4,381 3,027
Property, Plant and Equipment, Net:
Property, plant and equipment 42,667 40,396
Less: accumulated depreciation and amortization 10,578 10,543
Property, plant and equipment, net
32,089 29,853
Other Assets:
Goodwill 3,943 4,160
Regulatory assets ($313 and $402 related to VIEs, respectively)
3,108 2,513
Other non-current assets 247 162
Total other assets 7,298 6,835
Total Assets $ 43,768 $ 39,715
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS - (continued)
December 31, 2024 December 31, 2023
(in millions, except par value and shares)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Short-term borrowings $ 500 $ 4
Current portion of VIE Securitization Bonds long-term debt 13 178
Indexed debt, net 2 5
Current portion of other long-term debt 51 872
Indexed debt securities derivative 619 605
Accounts payable 1,320 917
Taxes accrued 329 291
Interest accrued 274 236
Dividends accrued 143 126
Customer deposits 93 111
Current liabilities held for sale
176 -
Other current liabilities 525 519
Total current liabilities 4,045 3,864
Other Liabilities:
Deferred income taxes, net 4,389 4,079
Benefit obligations 550 572
Regulatory liabilities 2,999 3,208
Other non-current liabilities 722 766
Total other liabilities 8,660 8,625
Long-term Debt, net:
VIE Securitization Bonds, net 308 320
Other long-term debt, net 20,089 17,239
Total long-term debt, net 20,397 17,559
Commitments and Contingencies (Note 14)
Shareholders’ Equity:
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 651,727,276 shares and 631,225,829 shares outstanding, respectively
6 6
Additional paid-in capital 9,105 8,604
Retained earnings 1,572 1,092
Accumulated other comprehensive loss (17) (35)
Total shareholders’ equity 10,666 9,667
Total Liabilities and Shareholders’ Equity $ 43,768 $ 39,715
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
2024 2023 2022
(in millions)
Cash Flows from Operating Activities:
Net income $ 1,019 $ 917 $ 1,057
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 1,439 1,401 1,288
Deferred income taxes 221 31 20
Loss (gain) on divestitures - 13 (303)
Loss (gain) on equity securities (20) (31) 227
Loss (gain) on indexed debt securities 14 27 (325)
Pension contributions (30) (32) (35)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net (84) 423 (461)
Inventory 42 167 (259)
Taxes receivable (27) (74) (19)
Accounts payable 210 (302) 203
Current regulatory assets and liabilities
(86) 1,152 67
Non-current regulatory assets and liabilities
(644) (109) 167
Other current assets and liabilities 101 162 (5)
Other non-current assets and liabilities (30) 72 109
Other operating activities, net 14 60 79
Net cash provided by operating activities 2,139 3,877 1,810
Cash Flows from Investing Activities:
Capital expenditures (4,513) (4,401) (4,419)
Proceeds from sale of equity securities, net of transaction costs - - 702
Proceeds from divestitures
- 144 2,075
Other investing activities, net 24 24 14
Net cash used in investing activities (4,489) (4,233) (1,628)
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net (4) (10) 452
Payment of obligation for finance lease - - (485)
Payments of commercial paper, net
(539) (1,055) (74)
Proceeds from long-term debt and term loans, net
3,955 6,044 2,089
Payments of long-term debt and term loans, including make-whole premiums (1,050) (3,190) (1,795)
Payment of debt issuance costs (35) (55) (36)
Payment of dividends on Common Stock (522) (485) (440)
Payment of dividends on Preferred Stock - (50) (49)
Proceeds from issuance of Common Stock, net 494 - -
Redemption of Series A Preferred Stock - (800) -
Other financing activities, net (28) (25) (7)
Net cash provided by (used in) financing activities 2,271 374 (345)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash (79) 18 (163)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period
109 91 254
Cash, Cash Equivalents and Restricted Cash at End of Period
$ 30 $ 109 $ 91
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY
2024 2023 2022
Shares Amount Shares Amount Shares Amount
(in millions of dollars and shares, except authorized shares and per share amounts)
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares
Balance, beginning of year - $ - 1 $ 790 1 $ 790
Redemption of Series A Preferred Stock - - (1) (790) - -
Balance, end of year - - - - 1 790
Common Stock, $0.01 par value; authorized 1,000,000,000 shares
Balance, beginning of year 631 6 630 6 629 6
Issuances of Common Stock 19 - - - - -
Issuances related to benefit and investment plans 2 - 1 - 1 -
Balance, end of year 652 6 631 6 630 6
Additional Paid-in-Capital
Balance, beginning of year 8,604 8,568 8,529
Issuances of Common Stock, net of issuance costs 494 - -
Issuances related to benefit and investment plans 7 36 39
Balance, end of year 9,105 8,604 8,568
Retained Earnings
Balance, beginning of year 1,092 709 154
Net income 1,019 917 1,057
Common Stock dividends declared (see Note 11)
(539) (492) (453)
Series A Preferred Stock dividends declared (see Note 11)
- (42) (49)
Balance, end of year 1,572 1,092 709
Accumulated Other Comprehensive Loss
Balance, beginning of year (35) (31) (64)
Other comprehensive income (loss) 18 (4) 33
Balance, end of year (17) (35) (31)
Total Shareholders’ Equity $ 10,666 $ 9,667 $ 10,042
See Combined Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Member of CenterPoint Energy Houston Electric, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of CenterPoint Energy Houston Electric, LLC and subsidiaries (an indirect wholly-owned subsidiary of CenterPoint Energy, Inc.) (the “Company”) as of December 31, 2024 and 2023, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements - Refer to Note 7 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Public Utility Commission of Texas (“PUCT”), which has jurisdiction with respect to the rates of electric transmission and distribution companies in Texas. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. The impacts of accounting for the economics of rate regulation are pervasive to the financial statements and disclosures.
The Company’s rates are subject to regulatory rate-setting processes by the PUCT. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered in rates. The PUCT’s regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the PUCT in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has
indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.
We identified rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory actions on the financial statements. Management’s judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company, and (3) refunds to customers. Given that certain of management’s accounting judgments are based on assumptions about the outcome of decisions by the PUCT, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential uncertainty of decisions by the PUCT included the following, among others:
•We evaluated the Company’s disclosures related to the effects of rate regulation by testing certain recorded balances and evaluating regulatory developments.
•We read relevant regulatory orders issued by the PUCT, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected the Company’s filings with the PUCT and the filings with the PUCT by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the PUCT’s treatment of similar costs under similar circumstances.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 20, 2025
We have served as the Company's auditor since 1932.
CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
2024 2023 2022
(in millions)
Revenues $ 3,939 $ 3,677 $ 3,412
Expenses:
Operation and maintenance 1,927 1,673 1,650
Depreciation and amortization 762 748 670
Taxes other than income taxes 295 262 261
Total 2,984 2,683 2,581
Operating Income 955 994 831
Other Income (Expense):
Interest expense and other finance charges (311) (259) (202)
Interest expense on Securitization Bonds (3) (8) (13)
Other income, net 43 34 19
Total (271) (233) (196)
Income Before Income Taxes 684 761 635
Income tax expense 138 168 125
Net Income $ 546 $ 593 $ 510
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
2024 2023 2022
(in millions)
Net income $ 546 $ 593 $ 510
Other comprehensive income:
Adjustment to pension and other postretirement plans (net of tax of $-0-, $-0- and $-0-)
(1) - -
Total (1) - -
Comprehensive income $ 545 $ 593 $ 510
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS
December 31, 2024 December 31, 2023
(in millions)
ASSETS
Current Assets:
Cash and cash equivalents ($14 and $76 related to VIEs, respectively)
$ 14 $ 76
Accounts and notes receivable, net ($0 and $19 related to VIEs, respectively), less allowance for credit losses of $2 and $1, respectively
307 295
Accounts and notes receivable-affiliated companies 371 251
Accrued unbilled revenues 137 142
Materials and supplies 392 409
Taxes receivable - 38
Prepaid expenses and other current assets ($0 and $13 related to VIEs, respectively)
44 48
Total current assets 1,265 1,259
Property, Plant and Equipment, Net
Property, plant and equipment 21,750 19,515
Less: accumulated depreciation and amortization 4,628 4,469
Property, plant and equipment, net 17,122 15,046
Other Assets:
Regulatory assets ($0 and $74 related to VIEs, respectively)
1,284 752
Other non-current assets 41 29
Total other assets 1,325 781
Total Assets $ 19,712 $ 17,086
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS - (continued)
December 31, 2024 December 31, 2023
(in millions)
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Short-term borrowings
$ 500 $ -
Current portion of VIE Securitization Bonds long-term debt - 161
Accounts payable 681 351
Accounts payable-affiliated companies
119 104
Taxes accrued 189 155
Interest accrued 108 99
Other current liabilities 144 111
Total current liabilities 1,741 981
Other Liabilities:
Deferred income taxes, net 1,502 1,406
Benefit obligations 32 32
Regulatory liabilities 861 1,025
Other non-current liabilities 95 107
Total other liabilities 2,490 2,570
Long-Term Debt, net
8,322 7,426
Commitments and Contingencies (Note 14)
Member’s Equity:
Common stock - -
Additional paid-in capital 5,589 4,745
Retained earnings 1,571 1,364
Accumulated other comprehensive loss (1) -
Total member’s equity 7,159 6,109
Total Liabilities and Member’s Equity $ 19,712 $ 17,086
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
2024 2023 2022
(in millions)
Cash Flows from Operating Activities:
Net income $ 546 $ 593 $ 510
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 762 748 670
Deferred income taxes 61 160 86
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net
(10) 16 (63)
Accounts receivable/payable-affiliated companies 25 (1) 47
Inventory 17 62 (179)
Accounts payable 89 (60) (7)
Taxes receivable 38 (38) -
Current regulatory assets and liabilities
2 6 (20)
Non-current regulatory assets and liabilities
(608) (136) (21)
Other current assets and liabilities 43 28 (20)
Other non-current assets and liabilities (8) 35 (25)
Other operating activities, net 3 (12) (12)
Net cash provided by operating activities 960 1,401 966
Cash Flows from Investing Activities:
Capital expenditures (2,642) (2,279) (2,436)
Increase in notes receivable-affiliated companies
(130) (238) -
Other investing activities, net 5 14 1
Net cash used in investing activities (2,767) (2,503) (2,435)
Cash Flows from Financing Activities:
Proceeds from long-term debt and term loan, net
1,397 1,398 1,589
Payments of long-term debt (161) (156) (720)
Increase (decrease) in notes payable-affiliated companies - (642) 130
Payment of debt issuance costs (8) (13) (17)
Contribution from parent 844 885 1,143
Dividend to parent
(339) (367) (316)
Payment of obligation for finance lease - - (485)
Other financing activities, net (1) (2) -
Net cash provided by financing activities 1,732 1,103 1,324
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash (75) 1 (145)
Cash, Cash Equivalents and Restricted Cash at Beginning of the Period
89 88 233
Cash, Cash Equivalents and Restricted Cash at End of the Period
$ 14 $ 89 $ 88
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY
2024 2023 2022
Shares Amount Shares Amount Shares Amount
(in millions, except share amounts)
Common Stock
Balance, beginning of year 1,000 $ - 1,000 $ - 1,000 $ -
Balance, end of year 1,000 - 1,000 - 1,000 -
Additional Paid-in-Capital
Balance, beginning of year 4,745 3,860 2,678
Non-cash contribution from parent - - 38
Contribution from parent 844 885 1,143
Other - - 1
Balance, end of year 5,589 4,745 3,860
Retained Earnings
Balance, beginning of year 1,364 1,138 944
Net income 546 593 510
Dividend to parent (339) (367) (316)
Balance, end of year 1,571 1,364 1,138
Accumulated Other Comprehensive Loss
Balance, beginning of year - - -
Other comprehensive loss
(1) - -
Balance, end of year (1) - -
Total Member’s Equity $ 7,159 $ 6,109 $ 4,998
See Combined Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder of CenterPoint Energy Resources Corp.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of CenterPoint Energy Resources Corp. and subsidiaries (an indirect wholly-owned subsidiary of CenterPoint Energy, Inc.) (the “Company”) as of December 31, 2024 and 2023, the related statements of consolidated income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements - Refer to Note 7 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of gas transmission and distribution companies in those jurisdictions. Management has determined its regulated operations meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. The impacts of accounting for the economics of rate regulation are pervasive to the financial statements and disclosures.
The Company’s rates are subject to regulatory rate-setting processes by the Commissions. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in the utility business. Regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investment, and the timing and amount of assets to be recovered in rates. The Commissions’ regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the
amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.
We identified rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about certain affected account balances and disclosures and the high degree of subjectivity involved in assessing the impact of regulatory actions on the financial statements. Management’s judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of capital investments made by the Company and (3) refunds to customers. Given that certain of management’s accounting judgments are based on assumptions about the outcome of decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the potential uncertainty of decisions by the Commissions included the following, among others:
•We evaluated the Company’s disclosures related to the effects of rate regulation by testing certain recorded balances and evaluating regulatory developments.
•We read relevant regulatory orders issued by the Commissions, regulatory statutes, filings made by the Company and intervenors, and other external information. We evaluated relevant external information and compared it to certain recorded regulatory asset and liability balances for completeness.
•For certain regulatory matters, we inspected the Company’s filings with the Commissions and the filings with the Commissions by intervenors to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 20, 2025
We have served as the Company's auditor since 1997.
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
2024 2023 2022
(in millions)
Revenues:
Utility revenues $ 3,878 $ 4,107 $ 4,764
Non-utility revenues 47 42 36
Total 3,925 4,149 4,800
Expenses:
Utility natural gas 1,489 1,856 2,607
Non-utility cost of revenues, including natural gas 3 3 4
Operation and maintenance 848 904 886
Depreciation and amortization 522 493 448
Taxes other than income taxes 234 243 257
Total 3,096 3,499 4,202
Operating Income 829 650 598
Other Income (Expense):
Gain on sale - - 557
Interest expense and other finance charges (197) (178) (130)
Other income (expense), net 12 14 (64)
Total (185) (164) 363
Income Before Income Taxes 644 486 961
Income tax expense (benefit) 104 (26) 236
Net Income $ 540 $ 512 $ 725
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
2024 2023 2022
(in millions)
Net income $ 540 $ 512 $ 725
Other comprehensive income:
Adjustment to pension and other postretirement plans (net of tax of $-0-, $-0- and $4)
1 - 6
Total
1 - 6
Comprehensive income $ 541 $ 512 $ 731
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS
December 31, 2024 December 31, 2023
(in millions)
ASSETS
Current Assets:
Cash and cash equivalents $ 2 $ 1
Accounts receivable, less allowance for credit losses of $24 and $25, respectively
349 356
Accrued unbilled revenue, less allowance for credit losses of $2 and $1, respectively
338 329
Accounts and notes receivable - affiliated companies 6 43
Material and supplies 105 107
Natural gas inventory 137 156
Taxes receivable 46 101
Current assets held for sale
1,266 -
Regulatory assets 238 161
Prepaid expenses and other current assets 50 55
Total current assets 2,537 1,309
Property, Plant and Equipment, Net:
Property, plant and equipment 15,552 15,672
Less: accumulated depreciation and amortization 4,146 4,169
Property, plant and equipment, net 11,406 11,503
Other Assets:
Goodwill 1,461 1,583
Regulatory assets 903 850
Other non-current assets 118 51
Total other assets 2,482 2,484
Total Assets $ 16,425 $ 15,296
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS - (continued)
December 31, 2024 December 31, 2023
(in millions)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term borrowings $ - $ 4
Current portion of long-term debt 10 -
Accounts payable 405 392
Accounts payable-affiliated companies
101 99
Taxes accrued 150 145
Interest accrued 82 70
Customer deposits 81 95
Current liabilities held for sale
176 -
Other current liabilities 255 282
Total current liabilities 1,260 1,087
Other Liabilities:
Deferred income taxes, net 1,370 1,246
Benefit obligations 63 74
Regulatory liabilities 1,887 1,882
Other non-current liabilities 403 458
Total other liabilities 3,723 3,660
Long-Term Debt, net 5,174 4,670
Commitments and Contingencies (Note 14)
Stockholder’s Equity:
Common stock - -
Additional paid-in capital 4,519 4,229
Retained earnings 1,732 1,634
Accumulated other comprehensive income 17 16
Total stockholder’s equity 6,268 5,879
Total Liabilities and Stockholder’s Equity
$ 16,425 $ 15,296
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
2024 2023 2022
(in millions)
Cash Flows from Operating Activities:
Net income $ 540 $ 512 $ 725
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 522 493 448
Deferred income taxes 55 (41) 178
Gain on divestitures - - (557)
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net (73) 410 (376)
Accounts receivable/payable-affiliated companies 38 (81) 41
Inventory 6 101 (50)
Taxes receivable 55 (89) -
Accounts payable 43 (250) 190
Current regulatory assets and liabilities
(85) 1,098 112
Non-current regulatory assets and liabilities
(31) 54 132
Other current assets and liabilities 24 85 13
Other non-current assets and liabilities (2) (1) (2)
Other operating activities, net (24) 21 2
Net cash provided by operating activities
1,068 2,312 856
Cash Flows from Investing Activities:
Capital expenditures (1,439) (1,619) (1,661)
Decrease (increase) in notes receivable-affiliated companies
1 (1) -
Proceeds from divestitures
- - 2,075
Other investing activities, net 19 (23) (8)
Net cash provided by (used in) investing activities
(1,419) (1,643) 406
Cash Flows from Financing Activities:
Increase (decrease) in short-term borrowings, net
(4) (10) 452
Payments of commercial paper, net
115 (321) (94)
Proceeds from long-term debt and term loans, net
399 2,006 927
Payments of long-term debt and term loans
- (2,332) (475)
Increase in notes payable-affiliated companies
- - (1,517)
Payments of debt issuance costs
(3) (14) (14)
Contribution from parent 290 500 289
Dividends to parent
(442) (496) (844)
Other financing activities, net (3) (1) (1)
Net cash provided by (used in) financing activities
352 (668) (1,277)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 1 1 (15)
Cash, Cash Equivalents and Restricted Cash at Beginning of Period
1 - 15
Cash, Cash Equivalents and Restricted Cash at End of Period
$ 2 $ 1 $ -
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT, WHOLLY-OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY
2024 2023 2022
Shares Amount Shares Amount Shares Amount
(in millions, except share amounts)
Common Stock
Balance, beginning of year 1,000 $ - 1,000 $ - 1,000 $ -
Balance, end of year 1,000 - 1,000 - 1,000 -
Additional Paid-in-Capital
Balance, beginning of year 4,229 3,729 4,106
Non-cash contribution from parent - - 54
Contribution from parent 290 500 289
Dividend to parent for sale of Arkansas and Oklahoma Natural Gas businesses - - (720)
Balance, end of year 4,519 4,229 3,729
Retained Earnings
Balance, beginning of year 1,634 1,618 1,017
Net income 540 512 725
Dividend to parent (442) (496) (124)
Balance, end of year 1,732 1,634 1,618
Accumulated Other Comprehensive Income
Balance, beginning of year 16 16 10
Other comprehensive income
1 - 6
Balance, end of year 17 16 16
Total Stockholder’s Equity $ 6,268 $ 5,879 $ 5,363
See Combined Notes to Consolidated Financial Statements
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Background and Basis of Presentation
General. This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants or the subsidiaries of CenterPoint Energy, Inc. other than itself or its subsidiaries.
Except as discussed in Note 12, no registrant has an obligation in respect of any other registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any registrant other than the obligor in making a decision with respect to such securities.
Basis of Presentation. Included in this combined Form 10-K are the consolidated financial statements of the Registrants. The Combined Notes to the Consolidated Financial Statements apply to all Registrants and specific references to Houston Electric and CERC herein also pertain to CenterPoint Energy, unless otherwise indicated. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
Background. CenterPoint Energy is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution systems.
As of December 31, 2024, CenterPoint Energy’s operating subsidiaries were as follows:
•Houston Electric owns and operates electric transmission and distribution facilities in the Texas Gulf Coast area that includes the city of Houston;
•CERC Corp. (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi and Texas, (ii) indirectly, through Indiana Gas and CEOH, owns and operates natural gas distribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; and
•SIGECO provides energy delivery services to electric and natural gas customers located in and near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market.
As of December 31, 2024, CenterPoint Energy’s reportable segments were Electric, Natural Gas, and Corporate and Other. Houston Electric and CERC each consist of a single reportable segment. For a description of CenterPoint Energy’s reportable segments, see Note 16.
On June 30, 2023, CenterPoint Energy completed the sale of its indirect subsidiary, Energy Systems Group, to an unaffiliated third party. On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. For additional information, see Note 4.
Principles of Consolidation. The accompanying consolidated financial statements are prepared in conformity with GAAP. The accounts of the Registrants and their wholly-owned and majority-owned and controlled subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation; however, intercompany profits have not been eliminated when such amounts are probable of recovery under the affiliates’ rate regulation process.
As of December 31, 2024, CenterPoint Energy, Houston Electric and SIGECO had VIEs including Bond Company IV and the SIGECO Securitization Subsidiary, which are consolidated. The consolidated VIEs are wholly-owned, bankruptcy-remote, special purpose entities that were formed solely for the purpose of securitizing transition property or facilitating the securitization financing of qualified costs. CenterPoint Energy, through SIGECO, has a controlling financial interest in the SIGECO Securitization Subsidiary and is the VIE’s primary beneficiary. For further information, see Note 7. Houston Electric has a controlling financial interest in Bond Company IV and is the VIE’s primary beneficiary. Creditors of CenterPoint Energy, Houston Electric and SIGECO have no recourse to any assets or revenues of Bond Company IV or the SIGECO Securitization Subsidiary, as applicable. The Securitization Bonds issued by these VIEs are payable only from and secured by transition or securitization property, as applicable, and the bondholders have no recourse to the general credit of CenterPoint Energy, Houston Electric or SIGECO.
(2) Summary of Significant Accounting Policies
(a)Use of Estimates
The preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(b)Revenues
The Registrants record revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on actual AMS meter data, supply volumes, estimated line loss and applicable tariff rates. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. For further discussion, see Note 5.
(c) MISO Transactions
Indiana Electric is a member of the MISO. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position, in which net purchases within that interval are recorded as Utility natural gas, fuel and purchased power and net sales within that interval are recorded as Utility revenues on CenterPoint Energy’s Statements of Consolidated Income. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured.
(d) Environmental Costs
The Registrants (i) expense or capitalize environmental expenditures, as appropriate, depending on their future economic benefit; (ii) expense amounts that relate to an existing condition caused by past operations that do not have future economic benefit; and (iii) record undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
(e) Cash and Cash Equivalents and Restricted Cash
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 Bond Companies and the SIGECO Securitization Subsidiary (VIEs) solely to support servicing the Securitization Bonds as of December 31, 2024 and 2023 are reflected on CenterPoint Energy’s and Houston Electric’s Consolidated Balance Sheets.
In connection with the issuance of Securitization Bonds, CenterPoint Energy and Houston Electric were required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds and are not included in cash and cash equivalents. For more information on restricted cash, see Note 17.
(f) Accounts Receivable and Allowance for Credit Losses
Accounts receivable are recorded at the invoiced amount and do not bear interest. Management reviews historical write-offs, current available information and reasonable and supportable forecasts to estimate and establish allowance for credit losses. Account balances are charged off against the allowance when management determines it is probable that the receivable will not be recovered. See Note 7 for further information about regulatory deferrals of bad debt expense, including those related to COVID-19 and the February 2021 Winter Storm Event.
(g) Inventory
The Registrants’ inventory consists principally of materials and supplies, and for CERC, natural gas, and for CenterPoint Energy, coal inventory. Materials and supplies are valued at the lower of average cost or market, are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Inventory related to CenterPoint Energy’s regulated operations is valued at historical cost consistent with ratemaking treatment. Coal inventory is valued at average cost. Certain natural gas in storage at CenterPoint Energy’s and CERC’s utilities are recorded using the last in, first out (LIFO) method. CenterPoint Energy’s and CERC’s balances in inventory that were valued using LIFO method were as follows:
Year Ended December 31,
2024 2023 (1) 2024 2023 (1)
CenterPoint Energy CERC
(in millions)
LIFO inventory $ 94 $ 106 $ 73 $ 86
(1)Based on the average cost of gas purchased during December 2024, CenterPoint Energy’s cost of replacing inventories carried at LIFO cost was $1 million less than the carrying value at December 31, 2024. CERC’s cost of replacing inventories carried at LIFO cost was $4 million more than the carrying value at December 31, 2024.
(h) Long-lived Assets
The Registrants record property, plant and equipment at historical cost and expense repair and maintenance costs as incurred.
The Registrants periodically evaluate long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. For rate-regulated businesses, recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. For businesses that are not rate-regulated, recoverability is assessed based on an estimate of undiscounted cash flows attributable to the assets compared to the carrying value of the assets. No long-lived asset impairments were recorded in 2024, 2023 or 2022.
The Registrants compute depreciation and amortization using the straight-line method based on economic lives or regulatory-mandated recovery periods. Amortization expense includes amortization of certain regulatory assets.
(i) Goodwill
CenterPoint Energy and CERC perform goodwill impairment tests at least annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Goodwill is evaluated for impairment by performing a qualitative assessment or using a quantitative test. If CenterPoint Energy or CERC chooses to perform a qualitative assessment and determine it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the quantitative test is then performed; otherwise, no further testing is required. The quantitative test, if required, is performed by comparing the fair value of each reporting unit with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is primarily determined based on an income approach or a weighted combination of income and market approaches. When the carrying amount is in excess of the estimated fair value of the reporting unit, the excess amount is recorded as an impairment charge, not to exceed the carrying amount of goodwill. CenterPoint Energy includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. For further information about the goodwill impairment tests, see Note 6.
(j) Regulatory Assets and Liabilities
The Registrants apply the guidance for accounting for regulated operations within the Electric reportable segment and the Natural Gas reportable segment. The Registrants’ rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings.
The Registrants’ rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reflected as an asset retirement liability in accordance with accounting guidance for AROs.
For further detail on the Registrants’ regulatory assets and liabilities, see Note 7.
(k) Capitalization and Deferral of Interest, including AFUDC
The Registrants capitalize interest and AFUDC as a component of projects under construction and amortize it over the assets’ estimated useful lives once the assets are placed in service. Additionally, the Registrants defer interest costs into a regulatory asset when amounts are probable of recovery. Deferred debt interest is amortized over the recovery period for rate-making purposes. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction for subsidiaries that apply the guidance for accounting for regulated operations. Although AFUDC increases both property, plant and equipment and earnings, it is realized in cash when the assets are included in rates. The table below includes interest capitalized or deferred for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Capitalized interest and AFUDC debt (1) $ 33 $ 18 $ 8 $ 32 $ 18 $ 6 $ 26 $ 14 $ 7
AFUDC equity (2) 66 33 17 62 32 14 37 24 5
Deferred debt interest (3) 65 24 36 65 16 43 51 12 36
(1)Included in Interest expense and other finance charges on the Registrants’ respective Statements of Consolidated Income.
(2)Included in Other income (expense), net on the Registrants’ respective Statements of Consolidated Income.
(3)Represents the amount on certain regulatory assets that are authorized to earn a return, such as debt post in-service carrying costs on property, plant and equipment, gas costs, storm restoration costs, and TEEEF (including returns on both regulatory and lease assets) and is included in Interest expense and other finance charges on the Registrants’ respective Statements of Consolidated Income.
(l) Leases
An arrangement is determined to be a lease at inception based on whether the Registrant has the right to control the use of an identified asset. ROU assets represent the Registrants’ right to use the underlying asset for the lease term and lease liabilities represent the Registrants’ obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Registrants are the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement date, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Each Registrant uses the implicit rate for agreements in which it is a lessor. Lease income and expense for operating leases and ROU amortization for finance leases are recognized on a straight-line basis over the lease term.
The Registrants have lease agreements with lease and non-lease components and have elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings and temporary generation. For classes of leases in which lease and non-lease components are not combined, consideration is allocated between components based on the stand-alone prices. Sublease income is not significant to the Registrants.
The Registrants’ lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. Except as described in Note 18, there are no lease transactions between related parties. Agreements in which the Registrants are lessors do not include provisions for the lessee to purchase the assets. Because risk is minimal, the Registrants do not take any significant actions to manage risk associated with the residual value of their leased assets.
The Registrants’ operating lease agreements are primarily equipment and real property leases, including land and office facility leases. CenterPoint Energy and Houston Electric also have finance lease agreements for temporary generation. The Registrants’ lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. The Registrants have elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842.
(m) Income Taxes
Houston Electric and CERC are included in CenterPoint Energy’s U.S. federal consolidated income tax return. Houston Electric and CERC report their income tax provision on a separate entity basis pursuant to a tax sharing policy with CenterPoint Energy. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy.
The Registrants use the asset and liability method of accounting for deferred income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. A valuation allowance is established against deferred tax assets for which management believes realization is not considered to be more likely than not. The Registrants recognize interest and penalties as a component of income tax expense (benefit), as applicable, in their respective Statements of Consolidated Income.
To the extent certain EDIT of the Registrants’ rate-regulated subsidiaries may be recoverable or payable through future rates, regulatory assets and liabilities have been recorded, respectively. See Note 13 for further discussion.
The Registrants use the portfolio approach to recognize income tax effects on other comprehensive income from accumulated other comprehensive income.
Investment tax credits are deferred and amortized to income over the approximate lives of the related property. Production tax credits extended by the IRA may be used to reduce current federal income taxes payable.
(n) Investments in Equity Securities (CenterPoint Energy)
CenterPoint Energy reports equity securities at estimated fair value in the Consolidated Balance Sheets, and any gains and losses, net of any transaction costs, are recorded as Gain (loss) on equity securities in the Statements of Consolidated Income.
(o) Assets Held for Sale
Generally, a long-lived asset to be sold is classified as held for sale in the period in which management, with approval from the Board of Directors, as applicable, commits to a plan to sell, and a sale is expected to be completed within one year. The Registrants record assets and liabilities held for sale, or the disposal group, at the lower of their carrying value or their estimated fair value less cost to sell. If a disposal group reflects a component of a reporting unit and meets the definition of a business, the goodwill within that reporting unit is allocated to the disposal group based on the relative fair value of the components representing a business that will be retained and disposed. Goodwill is not allocated to a portion of a reporting unit that does not meet the definition of a business.
As of December 31, 2024, certain assets and liabilities representing the Louisiana and Mississippi natural gas LDC businesses met the held for sale criteria. The sale will be considered an asset sale for tax purposes, requiring net deferred tax liabilities to be excluded from held for sale balances. For further discussion of the sale, see Note 4.
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, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value could be different if different estimates and assumptions in these valuation techniques were applied.
Fair value measurements require significant judgment and often 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. Changes in these assumptions could have a significant impact on the resulting fair value.
(p) Preferred Stock and Dividends
Preferred stock is evaluated to determine balance sheet classification, and all conversion and redemption features are evaluated for bifurcation treatment. Proceeds received net of issuance costs are recognized on the settlement date. Cash dividends become a liability once declared. Income available to common stockholders is computed by deducting from net income the dividends accumulated and earned during the period on cumulative preferred stock.
(q) Recent Accounting Pronouncements
On December 31, 2024, the Registrants adopted ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which updates segment disclosure requirements through enhanced disclosures around significant segment expenses. The Registrants applied the provision retrospectively to all periods presented for each Registrants’ reportable segment as further described. See Note 16 for further discussion of our segment reporting.
In November 2024, the FASB issued ASU 2024-03, Income Statement-Reporting Comprehensive Income (Topic 220): Expense Disaggregation Disclosures (“ASU 2024-03”). This ASU improves disclosure of a public business entity’s expense by requiring disaggregated disclosure of expenses in commonly presented expense captions. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and for interim periods beginning after December 15, 2027. Early adoption is permitted. The Registrants are currently evaluating the impact of this ASU on their respective consolidated financial statements.
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”). This ASU enhances the transparency of income tax disclosures related to rate reconciliation and income taxes. ASU 2023-09 is effective for annual periods beginning after December 15, 2024. Early adoption is permitted. The Registrants are currently evaluating the impact of this ASU on their respective consolidated financial statements.
Management believes that all other recently adopted and recently issued accounting standards that are not yet effective will not have a material impact on the Registrants’ financial position, results of operations or cash flows upon adoption.
(3) Property, Plant and Equipment
(a) Property, Plant and Equipment
Property, plant and equipment includes the following:
December 31, 2024 December 31, 2023
Weighted Average Useful Lives Property, Plant and Equipment, Gross Accumulated Depreciation & Amortization Property, Plant and Equipment, Net Property, Plant and Equipment, Gross Accumulated Depreciation & Amortization Property, Plant and Equipment, Net
(in years) (in millions)
CenterPoint Energy
Electric transmission and distribution 37 $ 21,387 $ 4,810 $ 16,577 $ 19,151 $ 4,762 $ 14,389
Electric generation (1) 25 1,107 154 953 1,381 315 1,066
Natural gas distribution 32 16,399 4,326 12,073 16,492 4,337 12,155
Finance ROU asset (2) 7.5 662 232 430 662 136 526
Other property 22 3,112 1,056 2,056 2,710 993 1,717
Total $ 42,667 $ 10,578 $ 32,089 $ 40,396 $ 10,543 $ 29,853
December 31, 2024 December 31, 2023
Weighted Average Useful Lives Property, Plant and Equipment, Gross Accumulated Depreciation & Amortization Property, Plant and Equipment, Net Property, Plant and Equipment, Gross Accumulated Depreciation & Amortization Property, Plant and Equipment, Net
(in years) (in millions)
Houston Electric
Electric transmission and distribution 37 $ 18,645 $ 3,647 $ 14,998 $ 16,800 $ 3,641 $ 13,159
Finance ROU asset (2) 7.5 662 232 430 662 136 526
Other property 20 2,443 749 1,694 2,053 692 1,361
Total $ 21,750 $ 4,628 $ 17,122 $ 19,515 $ 4,469 $ 15,046
CERC
Natural gas distribution 32 $ 15,474 $ 4,118 $ 11,356 $ 15,591 $ 4,136 $ 11,455
Other property 11 78 28 50 81 33 48
Total $ 15,552 $ 4,146 $ 11,406 $ 15,672 $ 4,169 $ 11,503
(1)SIGECO and AGC owned a 300 MW unit at the Warrick Power Plant (Warrick Unit 4) as tenants in common as of December 31, 2023. SIGECO’s share of the cost of this unit as of December 31, 2023, was $198 million with accumulated depreciation totaling $171 million. Under the operating agreement, AGC and SIGECO shared equally in the cost of operation and output of the unit. SIGECO’s share of operating costs was included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income. SIGECO exited joint operations of Warrick Unit 4 on January 1, 2024.
(2)Houston Electric recognized a finance ROU asset as of December 31, 2024 and December 31, 2023 related to temporary generation. See Note 19 for further discussion.
(b) Depreciation and Amortization
The following table presents depreciation and amortization expense for 2024, 2023 and 2022:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Depreciation $ 1,177 $ 545 $ 492 $ 1,092 $ 484 $ 459 $ 1,013 $ 434 $ 420
Amortization of securitized regulatory assets 90 74 - 163 155 - 191 191 -
Other amortization 172 143 30 146 109 34 84 45 28
Total $ 1,439 $ 762 $ 522 $ 1,401 $ 748 $ 493 $ 1,288 $ 670 $ 448
(c) AROs
The Registrants account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the timing of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Registrants recognize a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. The estimates of future liabilities are developed using a discounted cash flow model based upon estimates and assumptions of future costs, interest rates, credit-adjusted risk-free rates and the estimated timing of settlement.
The Registrants have recorded AROs associated with the removal of asbestos and asbestos-containing material in its buildings, including substation building structures. CenterPoint Energy recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley as well as certain sites in Indiana pursuant to the CCR Legacy Rule; see Note 14(d) for further discussion. CenterPoint Energy and Houston Electric also recorded AROs relating to treated wood poles for electric distribution, distribution transformers containing PCB (also known as Polychlorinated Biphenyl), and underground fuel storage tanks. CenterPoint Energy and CERC also recorded AROs relating to gas pipelines abandoned in place.
A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities on each of the Registrants’ respective Consolidated Balance Sheets is as follows:
December 31, 2024 December 31, 2023
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Beginning balance $ 590 $ 40 $ 380 $ 610 $ 36 $ 420
Additions 11 - - - - -
Accretion expense (1) 21 1 16 23 1 16
Revisions in estimates (2) (34) (2) (33) (43) 3 (56)
Ending balance $ 588 $ 39 $ 363 $ 590 $ 40 $ 380
(1)Reflected in Regulatory assets on each of the Registrants’ respective Consolidated Balance Sheets.
(2)In 2024 and 2023, CenterPoint Energy and CERC reflected a decrease in their respective ARO liability, which was primarily attributable to increases in the long-term interest rates used for discounting in the ARO calculation. In 2024, Houston Electric reflected a decrease in its ARO liability attributable to an increase in discount rates, while in 2023, Houston Electric reflected an increase in its ARO liability attributable to an increase in discount rates and disposal costs.
(4) Held for Sale and Divestitures (CenterPoint Energy and CERC)
Held for Sale. On February 19, 2024, CERC Corp. entered into the LAMS Asset Purchase Agreement, pursuant to which CERC Corp. agreed to sell its Louisiana and Mississippi natural gas LDC businesses. The purchase price for the Louisiana and Mississippi natural gas LDC businesses is $1.2 billion and subject to adjustment as set forth in the LAMS Asset Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing. The completion of the proposed transaction is subject to customary closing conditions, including (i) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (ii) approval of the LPSC, (iii) approval of the MPSC, (iv) no Material Adverse Effect (as defined in the LAMS Asset Purchase Agreement) having occurred and (v) customary closing conditions regarding the accuracy of the representations and warranties and compliance by the parties with the respective obligations under the LAMS Asset Purchase Agreement. The proposed transaction is not subject to a financing condition and is expected to close by the end of the first quarter of 2025, subject to satisfaction of the foregoing conditions. The businesses include approximately 12,000 miles of main pipeline in Louisiana and Mississippi serving more than 300,000 customers. The Louisiana and Mississippi natural gas LDC businesses are reflected in CenterPoint Energy’s Natural Gas reportable segment and CERC’s single reportable segment, as applicable. The transaction was approved by final orders issued by the MPSC on December 3, 2024 and the LPSC on December 17, 2024.
In February 2024, certain assets and liabilities representing the Louisiana and Mississippi natural gas LDC businesses met the held for sale criteria. The sale will be considered an asset sale for tax purposes, requiring net deferred tax liabilities to be excluded from held for sale balances.
The Registrants record assets and liabilities held for sale at the lower of their carrying value or their estimated fair value less cost to sell. Neither CenterPoint Energy nor CERC recognized any gains or losses upon classification of held for sale during the year ended December 31, 2024. If a 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. See Note 6 for further disclosure regarding the amount of goodwill allocated to the businesses to be sold.
The assets and liabilities of the Louisiana and Mississippi natural gas LDC businesses classified as held for sale in CenterPoint Energy’s and CERC’s Condensed Consolidated Balance Sheets, as applicable, included the following:
December 31, 2024
CenterPoint Energy CERC
(in millions)
Accounts receivable, net
$ 27 $ 27
Accrued unbilled revenues 26 26
Materials and supplies
13 13
Natural gas inventory 5 5
Property, plant and equipment, net 1,052 1,052
Goodwill 217 122
Regulatory assets 15 15
Other 6 6
Total current assets held for sale $ 1,361 $ 1,266
Short-term borrowings $ 3 $ 3
Accounts payable 44 44
Customer deposits 14 14
Regulatory liabilities 31 31
Other 84 84
Total current liabilities held for sale $ 176 $ 176
Although the Louisiana and Mississippi natural gas LDC businesses meet the held for sale criteria, their proposed disposals do not represent a strategic shift for CenterPoint Energy and CERC as both will retain significant operations in, and will continue to invest in, their natural gas businesses. Therefore, the assets and liabilities associated with these transactions are not reflected as discontinued operations on CenterPoint Energy’s and CERC’s Condensed Statements of Consolidated Income, as applicable, and the December 31, 2023 Condensed Consolidated Balance Sheets were not required to be recast for assets held for sale. Since the depreciation on the Louisiana and Mississippi natural gas LDC businesses assets will continue to be reflected in revenues through customer rates until the expected closing of the transaction and will be reflected in the carryover basis of the rate-regulated assets once sold, CenterPoint Energy and CERC will continue to record depreciation on those assets through the expected closing of the transaction.
The pre-tax income for the Louisiana and Mississippi natural gas LDC businesses, excluding interest and corporate allocations, included in CenterPoint Energy’s and CERC’s Statements of Consolidated Income is as follows:
Year Ended December 31,
2024 2023 2022
(in millions)
Income Before Income Taxes
$ 67 $ 44 $ 42
Divestiture of Energy Systems Group. On May 21, 2023, CenterPoint Energy, through its subsidiary 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, and CenterPoint Energy received $154 million in cash. In November 2024, CenterPoint Energy paid $2 million to ESG Holdings Group for working capital and other adjustments set forth in the Equity Purchase Agreement. For a discussion of CenterPoint Energy’s pre-disposition guarantees related to Energy Systems Group, see Note 14(c).
CenterPoint Energy recognized a loss on sale of approximately $13 million, including $3 million of transaction costs, during the year ended December 31, 2023, in connection with the closing of the sale of Energy Systems Group. Additionally, CenterPoint Energy recognized a current tax expense of $32 million during the year ended December 31, 2023, as a result of the cash taxes payable upon the closing of the sale.
The pre-tax income (loss) for Energy Systems Group, excluding interest and corporate allocations, included in CenterPoint Energy’s Statements of Consolidated Income is as follows:
Year Ended December 31,
2023 (1)
(in millions)
Income (Loss) Before Income Taxes
$ (4) $ 2
(1)Reflects January 1, 2023 to June 30, 2023 results only due to of the sale of Energy Systems Group.
Divestiture of Arkansas and Oklahoma Natural Gas Businesses (CenterPoint Energy and CERC). On April 29, 2021, CenterPoint Energy, through its subsidiary CERC Corp., entered into the AROK Asset Purchase Agreement to sell its Arkansas and Oklahoma Natural Gas businesses for $2.15 billion in cash, including recovery of approximately $425 million in natural gas costs, including storm-related incremental natural gas costs associated with the February 2021 Winter Storm Event, subject to certain adjustments set forth in the AROK Asset Purchase Agreement. The assets included approximately 17,000 miles of main pipeline in Arkansas, Oklahoma and certain portions of Bowie County, Texas serving more than half a million customers. The transaction closed on January 10, 2022.
The sale was considered an asset sale for tax purposes, requiring net deferred tax liabilities to be excluded from held for sale balances. The deferred taxes associated with the businesses were recognized as a deferred income tax benefit by CenterPoint Energy and CERC upon closing of the sale in 2022.
CenterPoint Energy and CERC recognized gains of $303 million and $557 million, respectively, net of transaction costs of $59 million, in connection with the closing of the disposition of the Arkansas and Oklahoma Natural Gas businesses during the year ended December 31, 2022. CenterPoint Energy and CERC collected a receivable of $15 million in May 2022 for full and final settlement of the working capital adjustment under the AROK Asset Purchase Agreement.
The pre-tax income for the Arkansas and Oklahoma Natural Gas businesses, excluding interest and corporate allocations, included in CenterPoint Energy’s and CERC’s Statements of Consolidated Income was $9 million for the year ended December 31, 2022, which only reflects January 1, 2022 to January 9, 2022 results due to the sale of the Arkansas and Oklahoma Natural Gas businesses previously described.
Effective on the date of the closing of the disposition of the Arkansas and Oklahoma Natural Gas businesses, a subsidiary of CenterPoint Energy entered into the Transition Services Agreement, whereby that subsidiary agreed to provide certain transition services such as accounting, customer operations, procurement, and technology functions for a term of up to twelve months. In November 2022, a significant majority of all services under the Transition Services Agreement were terminated, and on January 10, 2023, all remaining services were terminated.
CenterPoint Energy’s charges to Southern Col Midco for reimbursement of transition services was less than $1 million and $40 million during the years ended December 31, 2023 and 2022, respectively. Actual transition services costs incurred are recorded net of amounts charged to Southern Col Midco. CenterPoint Energy had no accounts receivable as of December 31, 2023 from Southern Col Midco for transition services.
(5) Revenue Recognition
In accordance with ASC 606, Revenue from Contracts with Customers, revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized reflects the consideration to which the Registrants expect to be entitled to receive in exchange for these goods or services.
ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Registrants recognize ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period.
The following tables disaggregate revenues by reportable segment and major source:
CenterPoint Energy
Year Ended December 31, 2024
Electric Natural Gas Corporate and Other Total
(in millions)
Revenue from contracts with customers $ 4,558 $ 3,990 $ 4 $ 8,552
Other (1)
32 58 3 93
Eliminations - (2) - (2)
Total revenues $ 4,590 $ 4,046 $ 7 $ 8,643
Year Ended December 31, 2023
Electric Natural Gas Corporate and Other Total
(in millions)
Revenue from contracts with customers $ 4,275 $ 4,210 $ 127 $ 8,612
Other (1)
15 69 3 87
Eliminations - (3) - (3)
Total revenues $ 4,290 $ 4,276 $ 130 $ 8,696
Year Ended December 31, 2022
Electric Natural Gas Corporate and Other Total
(in millions)
Revenue from contracts with customers $ 4,095 $ 4,969 $ 263 $ 9,327
Other (1)
13 (23) 4 (6)
Total revenues $ 4,108 $ 4,946 $ 267 $ 9,321
(1)Primarily consists of income from ARPs and leases.
Houston Electric
Year Ended December 31,
2024 2023 2022
(in millions)
Revenue from contracts with customers $ 3,930 $ 3,684 $ 3,417
Other (1) 9 (7) (5)
Total revenues $ 3,939 $ 3,677 $ 3,412
(1)Primarily consists of income from ARPs and leases.
CERC
Year Ended December 31,
2024 2023 2022
(in millions)
Revenue from contracts with customers $ 3,868 $ 4,083 $ 4,816
Other (1)
57 66 (16)
Total revenues $ 3,925 $ 4,149 $ 4,800
(1)Primarily consists of income from ARPs and leases.
Revenues from Contracts with Customers
Electric (CenterPoint Energy and Houston Electric). Houston Electric distributes electricity to customers over time and customers consume the electricity when delivered. Indiana Electric generates, distributes and transmits electricity to customers over time and customers consume the electricity when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by state regulators, such as the PUCT and the IURC, is recognized as electricity is delivered and represents amounts both billed and unbilled. Discretionary services requested by customers are provided at a point in time with control transferring upon the completion of the service. Revenue for discretionary services provided by Houston Electric is recognized upon completion of service based on the tariff rates set by the PUCT. Payments for electricity distribution and discretionary services are aggregated and received on a monthly basis. Houston Electric performs transmission services over time as a stand-ready obligation to provide a reliable network of transmission systems. Revenue is recognized upon time elapsed and the monthly tariff rate set by the regulator. Payments are received on a monthly basis. Indiana Electric customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing.
Natural Gas (CenterPoint Energy and CERC). CenterPoint Energy and CERC distribute and transport natural gas to customers over time and customers consume the natural gas when delivered. Revenue, consisting of both volumetric and fixed tariff rates set by the state governing agency for that service area, is recognized as natural gas is delivered and represents amounts both billed and unbilled. Discretionary services requested by the customer are provided at a point in time with control transferring upon completion of the service. Revenue for discretionary services is recognized upon completion of service based on the tariff rates set by the applicable state regulator. Payments of natural gas distribution, transportation and discretionary services are aggregated and received on a monthly basis.
Contract Balances. When the timing of delivery of service is different from the timing of the payments made by customers and when the right to consideration is conditioned on something other than the passage of time, the Registrants recognize a contract liability when customer payment precedes performance. Those customers that prepay are represented by contract liabilities until the performance obligations are satisfied. The Registrants’ contract liabilities are included in Accounts payable and Other current liabilities in their Consolidated Balance Sheets.
The opening and closing balances of accounts receivable, accrued unbilled revenues and contract liabilities from contracts with customers are as follows:
CenterPoint Energy
Accounts Receivable Accrued Unbilled Revenues Contract Liabilities
(in millions)
Opening balance as of December 31, 2023 $ 652 $ 516 $ 2
Closing balance as of December 31, 2024
666 521 2
Increase
$ 14 $ 5 $ -
The amount of revenue recognized in the year ended December 31, 2024 that was included in the opening contract liability was $2 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between CenterPoint Energy’s performance and the customer’s payment.
Houston Electric
Accounts Receivable Accrued Unbilled Revenues Contract Liabilities
(in millions)
Opening balance as of December 31, 2023 $ 275 $ 142 $ 2
Closing balance as of December 31, 2024 284 137 2
Increase (decrease)
$ 9 $ (5) $ -
The amount of revenue recognized in the year ended December 31, 2024 that was included in the opening contract liability was $2 million. The difference between the opening and closing balances of the contract liabilities primarily results from the timing difference between Houston Electric’s performance and the customer’s payment.
CERC
Accounts Receivable Accrued
Unbilled Revenues
(in millions)
Opening balance as of December 31, 2023 $ 330 $ 329
Closing balance as of December 31, 2024 326 338
Increase (decrease)
$ (4) $ 9
CERC does not have any opening or closing contract asset or contract liability balances.
Practical Expedients and Exemption. Sales taxes and other similar taxes collected from customers are excluded from the transaction price. For contracts for which revenue from the satisfaction of the performance obligations is recognized in the amount invoiced, the practical expedient was elected and revenue expected to be recognized on these contracts has not been disclosed.
Allowance for Credit Losses and Bad Debt Expense
CenterPoint Energy and CERC segregate financial assets that fall under the scope of ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, primarily trade receivables due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations and macroeconomic factors, among others. Houston Electric had no material changes in its methodology to recognize losses on financial assets that fall under the scope of Topic 326, primarily due to the nature of its customers and regulatory environment. For a discussion of regulatory deferrals, see Note 7.
The table below summarizes the Registrants’ bad debt expense amounts for 2024, 2023 and 2022, net of regulatory deferrals:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Bad debt expense $ 21 $ 1 $ 16 $ 18 $ - $ 16 $ 20 $ - $ 17
(6) Goodwill (CenterPoint Energy and CERC)
CenterPoint Energy’s goodwill by reportable segment is as follows for the periods presented:
Electric (1) Natural Gas Corporate and Other Total
(in millions)
Balance at December 31, 2022 $ 936 $ 2,920 $ 438 $ 4,294
Disposal (2) - - 134 134
Balance at December 31, 2023 936 2,920 304 4,160
Held for Sale (3) - 217 - 217
Balance at December 31, 2024 $ 936 $ 2,703 $ 304 $ 3,943
(1)Balances are presented net of the accumulated goodwill impairment charge of $185 million recorded in 2020.
(2)Represents goodwill attributable to the sale of Energy Systems Group. For further information, see Note 4.
(3)Represents goodwill attributable to the Louisiana and Mississippi natural gas LDC businesses classified as held for sale as of December 31, 2024. CenterPoint Energy did not recognize any goodwill impairments within the Natural Gas reportable segment for the year ended December 31, 2024. For further information, see Note 4.
There were no events impacting CERC’s goodwill for the year ended December 31, 2023. CERC’s goodwill is as follows for the periods presented:
December 31, 2023 Held for Sale (1)
December 31, 2024
(in millions)
Goodwill
$ 1,583 $ 122 $ 1,461
(1)Represents goodwill attributable to CERC to be disposed of as part of the potential sale of the Louisiana and Mississippi natural gas LDC businesses was classified as held for sale as of December 31, 2024. CERC did not recognize any goodwill impairments during the year ended December 31, 2024. For further information, see Note 4.
CenterPoint Energy and CERC performed their annual goodwill impairment tests in the third quarter of each of 2024 and 2023 and determined that no goodwill impairment charge was required for any reporting unit as a result of those tests.
(7) Regulatory Matters
The following is a list of regulatory assets and liabilities reflected on the Registrants’ respective Consolidated Balance Sheets as of December 31, 2024 and 2023:
December 31, 2024
CenterPoint Energy Houston Electric CERC
(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:
Benefit obligations (1) $ 373 $ - $ 4
Asset retirement obligations & other 304 80 188
Net deferred income taxes 144 47 69
Total future amounts recoverable from ratepayers 821 127 261
Amounts deferred for future recovery related to:
Cost recovery riders 145 - 83
Hurricanes and February 2021 Winter Storm Event Restoration Costs
145 145 -
May 2024 Storm Events 86 86 -
Hurricane Beryl 458 458 -
Hurricane Francine
19 19 -
Other regulatory assets 177 87 74
Decoupling 12 - 12
Temporary generation costs
71 71 -
Unrecognized equity return (2) (115) (77) (30)
Total amounts deferred for future recovery 998 789 139
Amounts currently recovered in customer rates related to:
Authorized trackers and cost deferrals 600 47 440
Securitized regulatory assets 343 - -
Unamortized loss on reacquired debt and hedging 93 63 10
Gas recovery costs 122 - 122
Decoupling
38 - 38
Extraordinary gas costs 133 - 133
Regulatory assets related to TCJA 47 47 -
Hurricanes and February 2021 Winter Storm Event Restoration Costs
31 5 26
Other regulatory assets 34 - 34
Benefit obligations 4 4 -
Temporary generation costs
219 219 -
Unrecognized equity return (3)
(136) (17) (62)
Total amounts recovered in customer rates (5)
1,528 368 741
Total Regulatory Assets $ 3,347 $ 1,284 $ 1,141
Total Current Regulatory Assets
$ 239 $ - $ 238
Total Non-Current Regulatory Assets
$ 3,108 $ 1,284 $ 903
Regulatory Liabilities:
Regulatory liabilities related to TCJA $ 1,346 $ 673 $ 501
Estimated removal costs 1,247 - 1,191
Other regulatory liabilities 454 195 235
Total Regulatory Liabilities $ 3,047 $ 868 $ 1,927
Total Current Regulatory Liabilities (6)
$ 48 $ 7 $ 40
Total Non-Current Regulatory Liabilities
$ 2,999 $ 861 $ 1,887
December 31, 2023
CenterPoint Energy Houston Electric CERC
(in millions)
Regulatory Assets:
Future amounts recoverable from ratepayers related to:
Benefit obligations (1) $ 379 $ - $ 5
Asset retirement obligations & other 290 75 186
Net deferred income taxes 96 41 42
Total future amounts recoverable from ratepayers 765 116 233
Amounts deferred for future recovery related to:
Cost recovery riders 113 - 73
Hurricanes and February 2021 Winter Storm Event restoration costs
149 123 26
Other regulatory assets 147 59 72
Gas recovery costs 27 - 27
Decoupling 17 - 17
COVID-19 incremental costs
12 8 4
Temporary generation costs
48 48 -
Unrecognized equity return (2) (63) (39) (16)
Total amounts deferred for future recovery 450 199 203
Amounts currently recovered in customer rates related to:
Authorized trackers and cost deferrals 535 44 375
Securitized regulatory assets 434 74 -
Unamortized loss on reacquired debt and hedging 106 72 11
Gas recovery costs 34 - 34
Extraordinary gas costs 208 - 208
Regulatory assets related to TCJA 47 47 -
Hurricane Harvey restoration costs 17 17 -
Benefit obligations 11 11 -
Temporary generation costs
208 208 -
Unrecognized equity return (4)
(141) (36) (53)
Total amounts recovered in customer rates
1,459 437 575
Total Regulatory Assets $ 2,674 $ 752 $ 1,011
Total Current Regulatory Assets
$ 161 $ - $ 161
Total Non-Current Regulatory Assets $ 2,513 $ 752 $ 850
Regulatory Liabilities:
Regulatory liabilities related to TCJA $ 1,377 $ 695 $ 505
Estimated removal costs 1,322 91 1,150
Other regulatory liabilities 548 245 260
Total Regulatory Liabilities $ 3,247 $ 1,031 $ 1,915
Total Current Regulatory Liabilities (6)
$ 39 $ 6 $ 33
Total Non-Current Regulatory Liabilities $ 3,208 $ 1,025 $ 1,882
(1)Pension and postretirement-related regulatory assets balances are actuarially valued annually.
(2)Represents the following: (a) CenterPoint Energy’s allowed equity return on post in-service carrying cost generally associated with investments in Indiana; (b) Houston Electric’s allowed equity return on TEEEF costs and storm restoration costs; and (c) CERC’s allowed equity return on post in-service carrying cost associated with certain distribution facilities replacements expenditures in Texas.
(3)Represents the following: (a) CenterPoint Energy’s allowed equity return on post in-service carrying cost generally associated with investments in Indiana; (b) Houston Electric’s allowed equity return on certain storm restoration balances and (c) CERC’s allowed equity return on post in-service carrying cost associated with certain distribution facilities replacements expenditures in Texas.
(4)Represents the following: (a) CenterPoint Energy’s allowed equity return on post in-service carrying cost generally associated with investments in Indiana; (b) Houston Electric’s allowed equity return on its true-up balance of stranded costs, other changes and related interest resulting from the formerly integrated electric utilities prior to Texas
deregulation to be recovered in rates through 2024 and certain storm restoration balances; and (c) CERC’s allowed equity return on post in-service carrying cost associated with certain distribution facilities replacements expenditures in Texas.
(5)Of the $1.5 billion, $368 million and $741 million currently being recovered in customer rates related to CenterPoint Energy, Houston Electric and CERC, respectively, $463 million, $305 million and $158 million is earning a return, respectively. The weighted average recovery period of regulatory assets currently being recovered in base rates, not earning a return, which totals $424 million, $63 million and $328 million for CenterPoint Energy, Houston Electric and CERC, respectively, is 11 years, 27 years and 7 years, respectively. Regulatory assets not earning a return with perpetual or undeterminable lives have been excluded from the weighted average recovery period calculation.
(6)Current regulatory liabilities are included in Other current liabilities in each of the Registrants’ respective Consolidated Balance Sheets.
The table below reflects the amount of allowed equity return recognized by each Registrant in its Statements of Consolidated Income for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Allowed equity return recognized $ 23 $ 20 $ 2 $ 41 $ 38 $ 2 $ 45 $ 42 $ 2
February 2021 Winter Storm Event
In February 2021, certain of the Registrants’ jurisdictions experienced an extreme and unprecedented winter weather event that resulted in prolonged freezing temperatures, which impacted their businesses. The February 2021 Winter Storm Event impacted wholesale prices of CenterPoint Energy’s and CERC’s natural gas purchases and their ability to serve customers in their Natural Gas service territories, including due to the reduction in available natural gas capacity and impacts to CenterPoint Energy’s and CERC’s natural gas supply portfolio activities, and the effects of weather on their systems and their ability to transport natural gas, among other things. The overall natural gas market, including the markets from which CenterPoint Energy and CERC sourced a significant portion of their natural gas for their operations, experienced significant impacts caused by the February 2021 Winter Storm Event, resulting in extraordinary increases in the cost of natural gas purchased by CenterPoint Energy and CERC of approximately $2 billion. CenterPoint Energy and CERC have completed recovery of natural gas costs in Mississippi, Indiana, Louisiana and Texas, and continue to recover the natural gas cost in Minnesota. As of December 31, 2024, CenterPoint Energy and CERC had each recorded current regulatory assets of $67 million and non-current regulatory assets of $67 million associated with the February 2021 Winter Storm Event. As of December 31, 2023, CenterPoint Energy and CERC have each recorded current regulatory assets of $86 million and non-current regulatory assets of $130 million associated with the February 2021 Winter Storm Event.
In Minnesota, the MPUC issued its written order on October 19, 2022 disallowing CERC’s recovery of approximately $36 million of the $409 million incurred, and CERC’s regulatory asset balance was reduced to reflect the disallowance. CERC filed a petition for reconsideration on November 8, 2022 and a written order denying the petition for reconsideration was issued on January 6, 2023.
As of December 31, 2024 and 2023, as authorized by the PUCT, both CenterPoint Energy and Houston Electric had each recorded a regulatory asset of $8 million for bad debt expenses resulting from REPs’ default on their obligation to pay delivery charges to Houston Electric net of collateral. Additionally, both CenterPoint Energy and Houston Electric had each recorded a regulatory asset of $19 million and $17 million as of December 31, 2024 and 2023, respectively, and requested reimbursement of costs associated with the February 2021 Winter Storm Event in Houston Electric’s rate case, which was filed in March 2024. On January 29, 2025 Houston Electric announced that a settlement agreement was reached with certain parties to the rate case filed on March 6, 2024, including the City of Houston and other regional municipalities. Subject to PUCT review and approval, the settlement is expected to result in approximately $50 million less annual revenue and an average decrease of approximately $1 a month for residential customers based on average usage of 1,000 kWh per month.
See Note 14(d) for further information regarding litigation related to the February 2021 Winter Storm Event.
Texas Public Securitization
The Texas Natural Gas Securitization Finance Corporation issued customer rate relief bonds in March 2023, and on March 23, 2023, CenterPoint Energy and CERC, collectively, received approximately $1.1 billion in cash proceeds from the issuance and sale of the state’s customer rate relief bonds. The proceeds from the state’s customer rate relief bonds included carrying costs incurred through August 2022. Incremental carrying costs incurred after August 2022 until the date the proceeds were received are recorded in a separate regulatory asset; the most recent CERC rate proceeding in Texas included a request for recovery of this regulatory asset and was included in the settlement agreement approved by the Railroad Commission in June 2024. As CenterPoint Energy and CERC have no future financial obligations for the repayment of the state’s customer rate relief bonds, the customer rate relief bonds are not recorded on CenterPoint Energy’s or CERC’s balance sheets. The state’s customer rate relief bonds are backed in part by customer rate relief property, including customer rate relief charges, which are non-bypassable uniform monthly volumetric charges to be paid by all existing and future sales customers as a component of each regulated utility’s gas cost, separate from their base rate. CERC only acts as a collection agent, whose duties include management, servicing and administration of a portion of the customer rate relief property which is associated with the customer rate relief charge imposed on customers of CERC under the guidance and direction from the Railroad Commission. The Texas Natural Gas Securitization Finance Corporation, and not CenterPoint Energy or CERC, is the owner of the customer rate relief property. The assets of the Texas Natural Gas Securitization Finance Corporation are not available to pay creditors of CenterPoint Energy, CERC, or their affiliates. While the customer rate relief charges will be included by CERC in their monthly billings, the billing amount is established by the Railroad Commission. CERC will remit all customer rate relief charges collected to the financing entity set up by the Railroad Commission. Therefore, the collection and servicing of customer rate relief charges have no impact on the respective Statements of Consolidated Income of CenterPoint Energy or CERC.
As U.S. GAAP has no specific accounting guidance for government grants or assistance, the cash proceeds from the state’s customer rate relief bonds were accounted for as a government grant by analogy to the grant model under IAS 20-Accounting for Government Grants and Disclosures of Government Assistance. CenterPoint Energy and CERC reflect the proceeds from the grant as a deduction to natural gas costs and recognized the $1.1 billion of cash proceeds from the state’s customer rate relief bonds within Utility natural gas expense on their respective Statements of Consolidated Income in the year ended December 31, 2023, net of the recognition of natural gas cost related to relieving CenterPoint Energy and CERC’s regulatory assets related to the February 2021 Winter Storm Event in the same period.
Indiana Electric Securitization of Generation Retirements (CenterPoint Energy)
On January 4, 2023, the IURC issued an order in accordance with Indiana Senate Enrolled Act 386 authorizing the issuance of up to $350 million in securitization bonds to securitize qualified costs associated with the retirements of Indiana Electric’s A.B. Brown coal-fired generation facilities. Accordingly, CenterPoint Energy determined that the retirement of property, plant and equipment became probable upon the issuance of the order. No loss on abandonment was recognized in connection with issuance of the order as there was no disallowance of all or part of the cost of the abandoned property, plant and equipment. In the first quarter of 2023, upon receipt of the order, CenterPoint Energy reclassified property, plant and equipment to be recovered through securitization to a regulatory asset and such amounts continued to earn a full return until recovered through securitization.
The SIGECO Securitization Subsidiary issued $341 million aggregate principal amount of the SIGECO Securitization Bonds on June 29, 2023. The SIGECO Securitization Subsidiary used a portion of the net proceeds from the issuance of the SIGECO Securitization Bonds to purchase the securitization property from SIGECO. No gain or loss was recognized.
The SIGECO Securitization Bonds are secured by the securitization property, which includes the right to recover, through non-bypassable securitization charges payable by SIGECO’s retail electric customers, the qualified costs of SIGECO authorized by the IURC order. The SIGECO Securitization Subsidiary, and not SIGECO, is the owner of the securitization property, and the assets of the SIGECO Securitization Subsidiary are not available to pay the creditors of SIGECO or its affiliates, other than the SIGECO Securitization Subsidiary. SIGECO has no payment obligations with respect to the SIGECO Securitization Bonds except to remit collections of securitization charges as set forth in a servicing agreement between SIGECO and the SIGECO Securitization Subsidiary. The non-bypassable securitization charges are subject to a true-up mechanism.
Houston Electric TEEEF
Pursuant to legislation passed in 2021, Houston Electric entered into two leases for TEEEF (temporary generation) which are detailed in Note 19. Houston Electric initially sought recovery of the lease costs and the applicable return as of December 31, 2021 under these lease agreements of approximately $200 million in its DCRF application filed with the PUCT on April 5,
2022, and subsequently amended on July 1, 2022, to show temporary generation in a separate Rider TEEEF. A final order was issued on April 5, 2023 approving a revenue requirement of $39 million that results in full recovery of costs requested but lengthens the amortization period for the short-term lease to be collected over 82.5 months. 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. The PUCT’s decision on the first TEEEF filing is now final and non-appealable.
On April 5, 2023, Houston Electric made its second TEEEF filing requesting recovery of TEEEF related costs incurred through December 31, 2022, which requested a new annual revenue requirement of approximately $188 million using 78 months to amortize the related deferred costs for proposed rates beginning September 2023, 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. Interim rates became effective on September 1, 2023, subject to surcharge or refund if they differ from the final rates approved by the PUCT. An agreement in principle was reached which reduced the annual revenue requirement by approximately $35 million based on recovering the balance as of December 31, 2022 over a 102-month amortization period (instead of the 78-month period in the initial filing) and also allowed for revised interim rates (to incorporate the agreement in principle and the initial interim rates that have been in place since September 1, 2023). The updated interim rates were implemented on December 15, 2023 and approved by the PUCT pursuant to its order issued on February 1, 2024 when the PUCT approved the agreement in principle. The PUCT’s decision on the second TEEEF filing is final and non-appealable.
On September 11, 2024, the TCA filed a complaint with the PUCT requesting that the PUCT modify its rulings with respect to its prior decisions related to the TEEEF filings made in 2022 and 2023. Specifically, TCA requested that the PUCT end cost recovery and return on investment on all the large 32 MW and 5 MW TEEEF units approved in docket 53442. On October 2, 2024, Houston Electric filed a response to the TCA complaint and requested that the complaint be dismissed due to the principles of res judicata and collateral estoppel. On October 8, 2024, TCA supplemented its complaint and on October 9, 2024, PUCT staff filed a statement of position stating that Houston Electric’s response provided a strong argument for dismissal of the complaint, but also stating that it would be prudent to have a thorough legal argument from TCA. On October 10, 2024, PUCT issued Order No. 2 finding the TCA complaint insufficient and requiring supplemental information or amendment from TCA by October 24, 2024; TCA filed supplemental information on October 24, 2024. On November 14, 2024, PUCT issued Order No. 4 denying the motion to reconsider and extending a deadline. On December 16, 2024, PUCT issued Order No. 5 granting waiver of the requirement for informal disposition and soliciting commission staff recommendation by January 16, 2025. On January 16, 2025, PUCT staff filed a supplemental recommendation recommending that the TCA has not met its requirement to first present its complaint to the City of Houston prior to presenting it to the PUCT. On January 17, 2025 the case was abated until February 28, 2025 to enable the TCA to present its complaint to the City of Houston.
On December 19, 2024, Houston Electric announced a proposal to release Houston Electric’s 15 large 27 MW to 32 MW TEEEF units to the San Antonio area prior to the summer of 2025. The proposal is intended to help ERCOT address a potential energy shortfall and Load Shed risk and to provide additional electric generation capacity to support growing energy demand in the greater San Antonio region. Under the proposal, Houston Electric would not receive revenue or profit from ERCOT and would also not charge Houston-area customers for these TEEEF units for the period when they are in San Antonio serving ERCOT, which is currently expected to be for a period of up to two years. Houston Electric would anticipate receiving revenues from one or more future transactions after the period the units are utilized to temporarily serve an energy need in the San Antonio area, and would therefore plan to continue to not charge customers for these units for any future periods. The proposal has not been finalized and is subject to the negotiation of definitive documentation among the relevant parties, as well as being subject to the approval of ERCOT and other stakeholders. It is not certain that mutually agreeable definitive documentation will be entered into at all or that all approvals will be obtained.
Houston Electric defers costs associated with the short-term and long-term leases that are probable of recovery and would otherwise be charged to expense in a regulatory asset, including allowed debt returns, and determined that such regulatory assets remain probable of recovery as of December 31, 2024. Right of use finance lease assets, such as assets acquired under the long-term leases, are evaluated for impairment under the long-lived asset impairment model by assessing if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. Houston Electric did not record any impairments on its right of use assets or regulatory asset in the years ended December 31, 2024 and 2023. See Note 19 for further information.
May 2024 Storm Events
Houston Electric’s service territory experienced sudden and destructive severe weather events in May 2024 that included hurricane-like winds and tornadoes. The May 2024 Storm Events caused significant damage to Houston Electric’s electric
delivery system. As of December 31, 2024, Houston Electric had recorded $345 million in Property, plant and equipment and $73 million in Regulatory assets, excluding carrying costs, for such restoration costs. Based on currently available information, as of December 31, 2024, Houston Electric estimates that total costs to restore the electric delivery facilities damaged as a result of the May 2024 Storm Events will be approximately $458 million, excluding carrying costs. These preliminary estimates are subject to revision as certain restoration costs are expected to be incurred through the end of 2025.
As is common with electric utilities serving coastal regions, the poles, towers, wires, street lights and pole-mounted equipment that comprise Houston Electric’s transmission and distribution system are not covered by property insurance. Houston Electric is deferring certain storm restoration costs as management believes it is probable that such costs will be recovered through the regulatory process. On November 8, 2024, Houston Electric filed an Application for Determination of System Restoration Costs with the PUCT. The application seeks a determination as to the reasonableness and necessity of approximately $502 million of costs (including estimated case processing expenses and carrying costs) incurred or expected to be incurred to restore service following the May 2024 Storm Events. On January 10, 2025, intervenors filed testimony recommending various disallowances ranging from $4.1 million to $101.9 million. On January 17, 2025, PUCT staff filed testimony recommending no adjustments to Houston Electric’s request. Houston Electric’s rebuttal testimony was filed January 21, 2025. On January 29, 2025, the parties represented to the ALJ that a settlement in principle had been reached and requested an abatement to memorialize and finalize the settlement. The case was abated and parties will file finalized settlement documents or a status update by February 26, 2025. Prior to authorizing Houston Electric to recover these costs, the PUCT must first determine the amount of reasonable and necessary system restoration costs. On January 24, 2025, Houston Electric filed a request for a Financing Order for the distribution costs included in the November 8, 2024 Application for Determination of System Restoration Costs. The ultimate recovery of the costs (or a portion thereof) is expected to be sought through the issuance and sale of non-recourse securitization bonds for distribution-related costs and the TCOS capital mechanism for transmission-related costs. However, neither the amount nor timing of the recovery is certain.
See Note 12 for further information regarding a term loan facility to fund certain costs related to the May 2024 Storm Events.
Hurricane Beryl
On July 8, 2024, Hurricane Beryl made landfall in Texas, bringing sustained winds, storm surges and torrential rain into Houston Electric’s service territory. Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system. Based on currently available information, as of December 31, 2024, Houston Electric estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Beryl will be approximately $1.1 billion, excluding carrying costs. As of December 31, 2024, Houston Electric had recorded $654 million in Property, plant and equipment and $442 million in Regulatory assets, excluding carrying costs, for such restoration costs.
Houston Electric is deferring certain storm restoration costs as management believes it is probable that such costs will be recovered through the regulatory process. Similar to the costs related to the May 2024 Storm Events, insurance coverage was not available for damages to much of our transmission and distribution assets. The ultimate recovery of the costs (or a portion thereof) relating to Hurricane Beryl is expected to be sought through the issuance and sale of non-recourse securitization bonds for distribution-related costs. However, neither the amount nor timing of the recovery is certain.
(8) Stock-Based Incentive Compensation Plans and Employee Benefit Plans
(a) Stock-Based Incentive Compensation Plans (CenterPoint Energy)
CenterPoint Energy has LTIPs that provide for the issuance of stock-based incentives, including stock options, performance awards, restricted stock unit awards and restricted and unrestricted stock awards to officers, employees and non-employee directors. Approximately 30 million shares of Common Stock are authorized under these plans for awards. CenterPoint Energy issues new shares of its Common Stock to satisfy stock-based payments related to LTIPs. Equity awards are granted to employees without cost to the participants.
Compensation costs for the performance awards and stock unit awards granted under LTIPs are measured using fair value and expected achievement levels on the grant date. For performance awards with operational goals, the achievement levels are revised as goals are evaluated. The fair value of awards granted to employees is based on the closing stock price of CenterPoint Energy’s Common Stock on the grant date. The compensation expense is recorded on a straight-line basis over the vesting period. Forfeitures are estimated on the date of grant based on historical averages and estimates are updated periodically throughout the vesting period.
The performance awards granted in 2024, 2023 and 2022 are distributed based upon the achievement of certain performance conditions or market conditions over a three-year performance cycle. The performance conditions are based on CenterPoint Energy’s cumulative adjusted EPS and certain carbon emissions reduction goals. The market condition is based on CenterPoint Energy’s total shareholder return relative to a specified peer group. Upon vesting, shares under the performance awards, as determined based on achievement of the applicable performance goals, are issued to the participants along with the value of dividend equivalents earned over the performance cycle.
The stock unit awards granted in 2024, 2023 and 2022 are service based and subject to CenterPoint Energy’s achievement of positive operating income for the last full calendar year preceding the applicable vesting date. Stock units awarded in 2024 are service based, and vest under a three-year ratable vesting schedule, with one-third vesting as of each of the first three anniversaries of the grant date. Each vesting is subject to the achievement of a performance goal. Stock unit awards granted to employees in 2023 and 2022 cliff vest at the end of a three-year period. Stock unit awards granted to non-employee directors vest immediately upon grant. Upon vesting, shares under the stock unit awards are issued to the participants along with the value of dividend equivalents earned over the applicable vesting period.
The following table summarizes CenterPoint Energy’s expenses related to LTIPs for the periods presented:
Year Ended December 31,
2024 2023 2022
(in millions)
LTIP compensation expense (1) $ 34 $ 65 $ 51
Income tax benefit recognized 8 15 12
Actual tax benefit realized for tax deductions 19 17 6
(1)Included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of any amounts capitalized.
The following tables summarize CenterPoint Energy’s LTIP activity for the year ended December 31, 2024:
Shares
(Thousands) Weighted-Average
Grant Date
Fair Value Remaining Average
Contractual
Life (Years) Aggregate
Intrinsic
Value (2) (Millions)
Performance Awards (1)
Outstanding and nonvested as of December 31, 2023 5,225 $ 25.95
Granted 1,727 27.92
Forfeited or canceled (220) 28.09
Vested and released to participants (1,824) 21.87
Outstanding and nonvested as of December 31, 2024 4,908 $ 28.14 1 $ 105
Stock Unit Awards
Outstanding and nonvested as of December 31, 2023 1,861 $ 26.91
Granted 438 28.25
Forfeited or canceled (43) 27.92
Vested and released to participants (1,139) 25.92
Outstanding and nonvested as of December 31, 2024 1,117 $ 28.20 0.5 $ 36
(1)Reflects maximum performance achievement.
(2)Reflects the impact of current expectations of achievement and stock price.
Additional information related to the Performance Awards and Stock Unit Awards was as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
(in millions, except for per unit amounts)
Performance Awards
Weighted-average grant date fair value per unit of awards granted $ 27.92 $ 29.18 $ 28.12
Total intrinsic value of awards received by participants 51 47 13
Vested grant date fair value 40 37 13
Stock Unit Awards
Weighted-average grant date fair value per unit of awards granted $ 28.25 $ 30.83 $ 28.44
Total intrinsic value of awards received by participants 33 28 14
Vested grant date fair value 30 23 13
As of December 31, 2024, there was $39 million of total unrecognized compensation cost related to nonvested performance and stock unit awards which is expected to be recognized over a weighted-average period of 1.7 years.
(b) Pension Benefits (CenterPoint Energy)
CenterPoint Energy maintains a non-contributory qualified defined benefit pension plan covering certain eligible employees, which is closed to new participants. CenterPoint Energy also maintains three additional qualified defined benefit pension plans, two of which are closed to new participants and one of which is frozen, that cover certain eligible employees and retirees of Vectren and are primarily non-contributory. In addition to the qualified defined benefit pension plans, CenterPoint Energy maintains unfunded non-qualified benefit restoration plans which allow participants to receive the benefits to which they would have been entitled under CenterPoint Energy’s 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 also maintains a frozen non-qualified supplemental retirement plan covering certain former executives of Vectren.
In December 2022, the CenterPoint Energy Retirement Plan, a tax-qualified defined benefit pension plan, completed the 2022 Annuity Purchase to fund the annuities of certain retirees of the non-regulated business units of CenterPoint Energy (including previously divested businesses), as part of a de-risking strategy. The 2022 Annuity Purchase reduced the plan’s benefit obligation by $138 million and plan assets by $136 million, which were transferred to the annuity provider. The $138 million transferred benefit obligation represented 9.4% of CenterPoint Energy’s total benefit obligation as of its last remeasurement prior to the transaction. As a result of this transaction, CenterPoint Energy incurred a settlement charge of $47 million. In addition, CenterPoint Energy was relieved of all responsibility for these pension obligations and the annuity
provider assumed the obligation to pay and administer the pension benefits for the 1,119 impacted retirees and beneficiaries, with no changes to the amount, timing or form of the benefit payments.
CenterPoint Energy’s net periodic cost includes the following components relating to pension, including the non-qualified benefit plans, for the periods presented:
Year Ended December 31,
2024 2023 2022
(in millions)
Service cost (1) $ 25 $ 25 $ 29
Interest cost (2) 73 76 73
Expected return on plan assets (2) (75) (76) (87)
Amortization of net loss (2) 28 28 31
Settlement cost (2) (3) - - 126
Net periodic cost $ 51 $ 53 $ 172
(1)Included in Operation and maintenance expense in CenterPoint Energy’s Statements of Consolidated Income, net of amounts capitalized and regulatory deferrals.
(2)Included in Other income (expense), net in CenterPoint Energy’s Statements of Consolidated Income, net of regulatory deferrals.
(3)A one-time, non-cash settlement cost is required when the total lump sum distributions or other settlements of plan benefit obligations during a plan year exceed the service cost and interest cost components of the net periodic cost for that year. In 2023 and 2022, CenterPoint Energy recognized non-cash settlement cost due to lump sum settlement payments. The transfer of assets related to the 2022 Annuity Purchase is considered a lump sum settlement payment.
CenterPoint Energy used the following assumptions to determine net periodic cost relating to pension benefits for the periods presented:
Year Ended December 31,
2024 2023 2022
Discount rate 4.95 % 5.15 % 2.80 %
Expected return on plan assets 6.50 6.50 5.00
Rate of increase in compensation levels 4.97 4.99 4.95
In determining net periodic benefit cost, CenterPoint Energy uses fair value, as of the beginning of the year, as its basis for determining expected return on plan assets except for two of Vectren’s qualified defined benefit pension plans which use a market related value of assets.
The following table summarizes changes in the benefit obligation, changes in plan assets, the amounts recognized in the Consolidated Balance Sheets as well as the key actuarial assumptions of CenterPoint Energy’s pension plans. The measurement dates for plan assets and benefit obligations were December 31, 2024 and 2023.
December 31, 2024 December 31, 2023
(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Benefit obligation, beginning of year $ 1,548 $ 1,553
Service cost 25 25
Interest cost 73 76
Benefits paid
(127) (147)
Actuarial (gain) loss (1) (42) 41
Benefit obligation, end of year 1,477 1,548
Change in Plan Assets
Fair value of plan assets, beginning of year 1,204 1,212
Employer contributions 30 32
Benefits paid
(127) (147)
Actual investment return 25 107
Fair value of plan assets, end of year 1,132 1,204
Funded status, end of year $ (345) $ (344)
Amounts Recognized in Balance Sheets
Non-current assets $ 7 $ 4
Current liabilities-other (7) (7)
Other liabilities-benefit obligations (345) (341)
Net liability, end of year $ (345) $ (344)
Actuarial Assumptions
Discount rate (2) 5.60 % 4.95 %
Expected return on plan assets (3) 7.00 6.50
Rate of increase in compensation levels 4.79 4.97
Interest crediting rate 3.00 3.00
(1)Significant sources of actuarial gain for 2024 include the increase in discount rate from 4.95% to 5.60%, offset by losses due to expected return on plan assets exceeding actual return on plan assets.
(2)The discount rate assumption was determined by matching the projected cash flows of CenterPoint Energy’s plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.
(3)The expected rate of return assumption was developed using the targeted asset allocation of CenterPoint Energy’s plans and the expected return for each asset class.
The following table displays pension benefits related to CenterPoint Energy’s pension plans that have accumulated benefit obligations in excess of plan assets as of the dates presented:
December 31, 2024 December 31, 2023
Pension
(Qualified) Pension
(Non-qualified) Pension
(Qualified) Pension
(Non-qualified)
(in millions)
Accumulated benefit obligation $ 1,431 $ 44 $ 1,496 $ 48
Projected benefit obligation 1,433 44 1,500 48
Fair value of plan assets 1,132 - 1,204 -
The accumulated benefit obligation for all defined benefit pension plans on CenterPoint Energy’s Consolidated Balance Sheets was $1,475 million and $1,544 million as of December 31, 2024 and 2023, respectively.
(c) Postretirement Benefits
CenterPoint Energy provides certain healthcare and life insurance benefits for eligible retired employees on both a contributory and non-contributory basis. The Registrants’ employees (other than employees of Vectren and its subsidiaries) who were hired before January 1, 2018 and who have met certain age and service requirements at retirement, as defined in the plan, are eligible to participate in these benefits, provided, however, that life insurance benefits are available only for eligible retired employees who retired before January 1, 2022. Employees hired on or after January 1, 2018 are not eligible for these benefits, except that such employees represented by IBEW Local Union 66 are eligible to participate in certain of the benefits, subject to the applicable age and service requirements. With respect to retiree medical and prescription drug benefits, and, effective January 1, 2021, dental and vision benefits, employees represented by the IBEW Local Union 66 who retire on or after January 1, 2017, and their dependents, receive any such benefits exclusively through the NECA/IBEW Family Medical Care Plan pursuant to the terms of the applicable collective bargaining agreement. Houston Electric and CERC are required to fund a portion of their obligations in accordance with rate orders. All other obligations are funded on a pay-as-you-go basis.
CenterPoint Energy, through Vectren, also maintains a postretirement benefit plan that provides health care and life insurance benefits, which are a combination of self-insured and fully insured programs, to eligible Vectren retirees on both a contributory and non-contributory basis.
Postretirement benefits are accrued over the active service period of employees. The net postretirement benefit cost includes the following components for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Service cost (1) $ 1 $ - $ 1 $ 1 $ - $ 1 $ 2 $ - $ 1
Interest cost (2) 13 5 4 13 5 5 9 4 3
Expected return on plan assets (2) (6) (4) (1) (5) (4) (1) (5) (4) (1)
Amortization of prior service cost (credit) (2) (2) (5) 2 (2) (5) 2 (3) (4) 2
Amortization of net loss (2) (8) (4) (3) (8) (4) (3) (4) (2) (1)
Net postretirement benefit cost (credit) $ (2) $ (8) $ 3 $ (1) $ (8) $ 4 $ (1) $ (6) $ 4
(1)Included in Operation and maintenance expense in each of the Registrants’ respective Statements of Consolidated Income, net of amounts capitalized and regulatory deferrals.
(2)Included in Other income (expense), net in each of the Registrants’ respective Statements of Consolidated Income, net of regulatory deferrals.
The following assumptions were used to determine net periodic cost relating to postretirement benefits for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
Discount rate 4.95 % 4.95 % 4.95 % 5.15 % 5.15 % 5.15 % 2.85 % 2.85 % 2.85 %
Expected return on plan assets 5.21 5.36 4.77 5.13 5.26 4.69 3.22 3.32 2.86
The following table summarizes changes in the benefit obligation, changes in plan assets, the amounts recognized in the Consolidated Balance Sheets and the key actuarial assumptions of the postretirement plans. The measurement dates for plan assets and benefit obligations were December 31, 2024 and 2023.
December 31, 2024 December 31, 2023
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions, except for actuarial assumptions)
Change in Benefit Obligation
Benefit obligation, beginning of year $ 263 $ 113 $ 93 $ 263 $ 115 $ 92
Service cost 1 - 1 1 - 1
Interest cost 13 5 4 13 5 5
Participant contributions 5 2 2 6 2 3
Benefits paid (21) (8) (9) (20) (8) (8)
Actuarial (gain) loss (1) (22) (9) (8) - (1) -
Other transfers
3 1 2 - - -
Benefit obligation, end of year 242 104 85 263 113 93
Change in Plan Assets
Fair value of plan assets, beginning of year 112 86 26 109 84 25
Employer contributions 9 1 5 7 - 4
Participant contributions 5 2 2 6 2 3
Benefits paid (21) (8) (9) (20) (8) (8)
Actual investment return 6 4 2 10 8 2
Other transfers
(8) (8) - - - -
Fair value of plan assets, end of year 103 77 26 112 86 26
Funded status, end of year $ (139) $ (27) $ (59) $ (151) $ (27) $ (67)
Amounts Recognized in Balance Sheets
Current liabilities - other $ (8) $ - $ (4) $ (7) $ - $ (4)
Other liabilities - benefit obligations (131) (27) (55) (144) (27) (63)
Net liability, end of year $ (139) $ (27) $ (59) $ (151) $ (27) $ (67)
Actuarial Assumptions
Discount rate (2) 5.60 % 5.60 % 5.60 % 4.95 % 4.95 % 4.95 %
Expected return on plan assets (3) 5.21 5.36 4.77 5.13 5.26 4.69
Medical cost trend rate assumed for the next year - Pre-65 6.75 6.75 6.75 7.25 7.25 7.25
Medical/prescription drug cost trend rate assumed for the next year - Post-65 13.74 13.74 13.74 22.76 22.76 22.76
Prescription drug cost trend rate assumed for the next year - Pre-65 10.00 10.00 10.00 9.00 9.00 9.00
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) 4.50 4.50 4.50 4.50 4.50 4.50
Year that the cost trend rates reach the ultimate trend rate - Pre-65 2034 2034 2034 2033 2033 2033
Year that the cost trend rates reach the ultimate trend rate - Post-65 2034 2034 2034 2033 2033 2033
(1)Significant sources of actuarial gain for 2024 include increase in discount rate from 4.95% to 5.60%, offset by losses from updated claims and demographic review.
(2)The discount rate assumption was determined by matching the projected cash flows of the plans against a hypothetical yield curve of high-quality corporate bonds represented by a series of annualized individual discount rates from one-half to 99 years.
(3)The expected rate of return assumption was developed using the targeted asset allocation of the plans and the expected return for each asset class.
(d) Accumulated Other Comprehensive Income (Loss) (CenterPoint Energy and CERC)
CenterPoint Energy recognizes the funded status of its pension and other postretirement plans on its Consolidated Balance Sheets. To the extent this obligation exceeds amounts previously recognized in the Statements of Consolidated Income, CenterPoint Energy records a regulatory asset for that portion related to its rate-regulated utilities. To the extent that excess liability does not relate to a rate-regulated utility, the offset is recorded as a reduction to equity in accumulated other comprehensive income.
Amounts recognized in accumulated other comprehensive loss (income) consist of the following as of the dates presented:
December 31, 2024 December 31, 2023
Pension
Benefits Postretirement
Benefits Pension
Benefits Postretirement
Benefits
CenterPoint Energy CenterPoint Energy CERC CenterPoint Energy CenterPoint Energy CERC
(in millions)
Unrecognized actuarial loss (gain) $ 52 $ (34) $ (26) $ 69 $ (34) $ (27)
Unrecognized prior service cost - 9 8 - 12 10
Net amount recognized in accumulated other comprehensive loss (income) $ 52 $ (25) $ (18) $ 69 $ (22) $ (17)
The changes in plan assets and benefit obligations recognized in other comprehensive income for the year ended December 31, 2024 are as follows:
Pension
Benefits Postretirement
Benefits
CenterPoint Energy CenterPoint Energy CERC
(in millions)
Net actuarial loss (gain)
$ (13) $ (4) $ -
Amortization of net actuarial loss (gain)
(4) 2 (2)
Amortization of prior service cost - (1) 1
Settlement - - -
Total recognized in comprehensive income $ (17) $ (3) $ (1)
Total recognized in net periodic costs and other comprehensive income
$ 34 $ 1 $ 2
(e) Pension Plan Assets (CenterPoint Energy)
In managing the investments associated with the benefit plans, CenterPoint Energy’s objective is to achieve and maintain a fully funded plan. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.
As part of the investment strategy discussed above, CenterPoint Energy maintained the following weighted-average allocation targets for its pension plans as of December 31, 2024:
Minimum Maximum
U.S. equity 17 % 27 %
International equity 9 % 19 %
Real estate 2 % 8 %
Fixed income 54 % 64 %
Cash 0 % 2 %
The following tables set forth by level, within the fair value hierarchy (see Note 9), CenterPoint Energy’s pension plan assets at fair value as of the dates presented:
December 31, 2024 December 31, 2023
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
(in millions)
Cash $ 36 $ - $ - $ 36 $ 21 $ - $ - $ 21
Equity securities:
U.S. companies 28 - - 28 30 - - 30
Cash received as collateral from securities lending 88 - - 88 94 - - 94
Obligation to return cash received as collateral from securities lending (88) - - (88) (94) - - (94)
U.S. treasuries and government agencies 156 - - 156 178 - - 178
Corporate bonds:
Investment grade or above - 428 - 428 - 469 - 469
Mortgage-backed securities
- 12 - 12 - 15 - 15
Asset-backed securities
- 1 - 1 - 1 - 1
Municipal bonds - 19 - 19 - 25 - 25
International government bonds - 13 - 13 - 9 - 9
Financial instruments - (3) - (3) - (4) - (4)
Total investments at fair value $ 220 $ 470 $ - 690 $ 229 $ 515 $ - 744
Investments measured by net asset value per share or its equivalent (1) (2) 442 460
Fair value of plan assets
$ 1,132 $ 1,204
(1)Represents investments in pooled investment funds and common collective trust funds.
(2)The amounts invested in pooled investment funds were 100% allocated to real estate. The amounts invested common collective trust funds were allocated as follows as of the dates presented:
December 31, 2024 December 31, 2023
International equities 38 % 40 %
U.S. equities 61 % 59 %
Fixed income 1 % 1 %
Level 2 investments, which do not have a quoted price in active market, are valued using the market data provided by independent pricing services or major market makers, to arrive at a price a dealer would pay for the security.
The pension plans utilized both exchange traded and over-the-counter financial instruments such as futures, interest rate options and swaps that were marked to market daily with the gains or losses settled in the cash accounts. The pension plans did not include any holdings of CenterPoint Energy Common Stock as of December 31, 2024 or 2023.
(f) Postretirement Plan Assets
In managing the investments associated with the postretirement plans, the Registrants’ primary objective is to preserve and improve the funded status of the plan, while minimizing volatility. This objective is expected to be achieved through an investment strategy that manages liquidity requirements while maintaining a long-term horizon in making investment decisions and efficient and effective management of plan assets.
As part of the investment strategy discussed above, the Registrants maintained the following weighted-average allocation targets for the postretirement plans as of December 31, 2024:
CenterPoint Energy Houston Electric CERC
Minimum Maximum Minimum Maximum Minimum Maximum
U.S. equities 14 % 24 % 13 % 23 % 15 % 25 %
International equities 3 % 13 % 3 % 13 % 2 % 12 %
Fixed income 69 % 79 % 69 % 79 % 68 % 78 %
Cash 0 % 2 % 0 % 2 % 0 % 2 %
The following table sets forth by level, within the fair value hierarchy (see Note 9), the Registrants’ postretirement plan assets, all of which were mutual funds, at fair value as of the dates presented:
December 31, 2024 December 31, 2023
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
(in millions)
CenterPoint Energy $ 103 $ - $ - $ 103 $ 113 $ - $ - $ 113
Houston Electric 77 - - 77 86 - - 86
CERC 26 - - 26 26 - - 26
The amounts invested in mutual funds were allocated as follows as of the dates presented:
December 31, 2024 December 31, 2023
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
U.S. equities 19 % 18 % 21 % 20 % 19 % 22 %
International equities 7 % 8 % 7 % 8 % 9 % 6 %
Fixed income 74 % 74 % 72 % 72 % 72 % 71 %
(g) Benefit Plan Contributions
The Registrants made the following contributions in 2024 and are required to make the following minimum contributions in 2025 to the indicated benefit plans below:
Contributions in 2024 Expected Minimum Contributions in 2025
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Qualified pension plans $ 23 $ - $ - $ 105 $ - $ -
Non-qualified pension plans 7 - - 7 - -
Postretirement benefit plans 9 1 5 8 1 5
Benefit payments are expected to be paid by the pension and postretirement benefit plans as follows:
Pension Benefits Postretirement Benefits
CenterPoint
Energy CenterPoint
Energy Houston Electric CERC
(in millions)
2025 $ 144 $ 16 $ 7 $ 6
2026 144 18 8 6
2027 141 19 8 7
2028 138 20 9 7
2029 134 21 9 7
2030-2034 609 102 46 35
(h) Savings Plan
CenterPoint Energy maintains the CenterPoint Energy Savings Plan, a tax-qualified employee savings plan that includes a cash or deferred arrangement under Section 401(k) of the Code and an employee stock ownership plan under Section 4975(e)(7) of the Code. Under the plan, participating employees may make pre-tax or Roth contributions and, if eligible, after-tax contributions up to certain federally mandated limits. Participating Registrants provide matching contributions and, as of January 1, 2020, for certain eligible employees, non-elective contributions up to certain limits.
The CenterPoint Energy Savings Plan has significant holdings of Common Stock. As of December 31, 2024, 7,136,941 shares of Common Stock were held by the savings plan, which represented approximately 6% of its investments. Given the concentration of the investments in Common Stock, the savings plan and its participants have market risk related to this investment. The savings plan limits the percentage of future contributions that can be invested in Common Stock to 25% and prohibits transfers of account balances where the transfer would result in more than 25% of a participant’s total account balance invested in Common Stock.
CenterPoint Energy allocates the savings plan benefit expense to Houston Electric and CERC related to their respective employees. The following table summarizes the Registrants’ savings plan benefit expense for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Savings plan benefit expenses (1)
$ 72 $ 27 $ 23 $ 67 $ 23 $ 20 $ 72 $ 23 $ 22
(1)Amounts presented in the table above are included in Operation and maintenance expense in the Registrants’ respective Statements of Consolidated Income and shown prior to any amounts capitalized.
(i) Other Benefits Plans
CenterPoint Energy maintains non-qualified deferred compensation plans that provide benefits payable to eligible directors, officers and select employees or their designated beneficiaries at specified future dates or upon termination, retirement or death. Benefit payments are made from the general assets of the participating Registrants or, in the case of certain plans, from a rabbi trust that is a grantor trust and remains subject to the claims of general creditors under applicable state and federal law.
Expenses related to other benefit plans were recorded as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Deferred compensation plans $ 3 $ - $ - $ (1) $ - $ - $ 1 $ - $ -
Amounts related to other benefit plans were included in Benefit Obligations in the Registrants’ accompanying Consolidated Balance Sheets as follows:
December 31, 2024 December 31, 2023
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Deferred compensation plans $ 22 $ 3 $ 1 $ 26 $ 3 $ 1
Split-dollar life insurance arrangements 46 1 - 46 1 -
(j) Change in Control Agreements and Other Employee Matters
CenterPoint Energy has a change in control plan, which was amended and restated on May 1, 2017. The plan generally provides, to the extent applicable, in the case of the occurrence of both a change in control of CenterPoint Energy and a covered
termination of employment, for severance benefits of up to three times annual base salary plus bonus and other benefits. Certain CenterPoint Energy officers are participants under the plan.
As of December 31, 2024, the Registrants’ employees were covered by collective bargaining agreements as follows:
Percentage of Employees Covered
Agreement Expiration CenterPoint Energy Houston Electric CERC
IBEW Local 66 May 2026 17 % 53 % - %
OPEIU Local 12 December 2025 2 % - % 2 %
Gas Workers Union Local 340 April 2025 5 % - % 12 %
IBEW Locals 1393 and USW Locals 12213 & 7441 December 2026 3 % - % 8 %
IBEW Locals 949 December 2025 3 % - % 7 %
USW Locals 13-227 June 2027 5 % - % 13 %
USW Locals 13-1 June 2027 - % - % 1 %
IBEW Local 702 June 2025 3 % - % - %
Teamsters Local 135/215 September 2027
- % - % - %
UWUA Local 175 October 2027
1 % - % 4 %
Total 39 % 53 % 47 %
The collective bargaining agreements with Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 related to CERC employees in Minnesota, as well as with IBEW Local 702 related to SIGECO employees, are scheduled to expire in April 2025, December 2025, December 2025 and June 2025, respectively, and negotiations of these agreements are expected to be completed before the respective expirations.
(9) Fair Value Measurements
Assets and liabilities that are recorded at fair value in the Registrants’ Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:
Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are exchange-traded derivatives and equity securities.
Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. A market approach is utilized to value the Registrants’ Level 2 natural gas derivative assets or liabilities. CenterPoint Energy’s Level 2 indexed debt securities derivative is valued using an option model and a discounted cash flow model, which uses projected dividends on the ZENS-Related Securities and a discount rate as observable inputs.
Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Registrants’ judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Registrants develop these inputs based on the best information available, including the Registrants’ own data.
The Registrants determine the appropriate level for each financial asset and liability on a quarterly basis and recognize transfers between levels at the end of the reporting period. As of December 31, 2024 and December 31, 2023, the Registrants did not have any assets or liabilities classified as Level 3.
The following tables present information about the Registrants’ assets and liabilities measured at fair value on a recurring basis as of December 31, 2024 and December 31, 2023 and indicate the fair value hierarchy of the valuation techniques utilized by the Registrants to determine such fair value:
CenterPoint Energy
December 31, 2024 December 31, 2023
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (in millions)
Equity securities $ 561 $ - $ - $ 561 $ 541 $ - $ - $ 541
Investments, including money market funds (1) 22 - - 22 31 - - 31
Natural gas derivatives (1)
- 1 - 1 - - - -
Total assets $ 583 $ 1 $ - $ 584 $ 572 $ - $ - $ 572
Liabilities
Indexed debt securities derivative $ - $ 619 $ - $ 619 $ - $ 605 $ - $ 605
Natural gas derivatives (2)
- 3 - 3 - 12 - 12
Total liabilities $ - $ 622 $ - $ 622 $ - $ 617 $ - $ 617
Houston Electric
December 31, 2024 December 31, 2023
Level 1
Level 2 Level 3 Total Level 1
Level 2 Level 3 Total
Assets (in millions)
Investments, including money market funds (1) $ 5 $ - $ - $ 5 $ 14 $ - $ - $ 14
Total assets $ 5 $ - $ - $ 5 $ 14 $ - $ - $ 14
CERC
December 31, 2024 December 31, 2023
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets (in millions)
Investments, including money market funds (1) $ 15 $ - $ - $ 15 $ 15 $ - $ - $ 15
Natural gas derivatives (1)
- 1 - 1 - - - -
Total assets $ 15 $ 1 $ - $ 16 $ 15 $ - $ - $ 15
Liabilities
Natural gas derivatives (2)
$ - $ 2 $ - $ 2 $ - $ 11 $ - $ 11
Total liabilities $ - $ 2 $ - $ 2 $ - $ 11 $ - $ 11
(1)Included in Prepaid expenses and other current assets in the respective Consolidated Balance Sheets.
(2)Included in Other current liabilities in the respective Consolidated Balance Sheets.
Items Measured at Fair Value on a Nonrecurring Basis
As a result of classifying the Louisiana and Mississippi natural gas LDC businesses as held for sale, CenterPoint Energy and CERC used a market approach consisting of contractual sales price adjusted for estimated working capital and other contractual purchase price adjustments to determine the fair value of the businesses classified as held for sale, which are Level 2 inputs. Neither CenterPoint Energy nor CERC recognized any gains or losses upon classification as held for sale for the year ended December 31, 2024. See Note 4 for further information.
Estimated Fair Value of Financial Instruments
The fair values of cash and cash equivalents, investments in equity securities measured at fair value and short-term borrowings under AMAs are estimated to be approximately equivalent to carrying amounts and have been excluded from the table below. The carrying amounts of non-trading derivative assets and liabilities and CenterPoint Energy’s ZENS indexed debt securities derivative are stated at fair value and are excluded from the table below. The fair value of each debt instrument is determined by multiplying the principal amount of each debt instrument by a combination of historical trading prices and
comparable issue data. These liabilities, which are not measured at fair value in the Registrants’ Consolidated Balance Sheets, but for which the fair value is disclosed, would be classified as Level 2 in the fair value hierarchy.
December 31, 2024 December 31, 2023
CenterPoint Energy (1) Houston Electric (1) CERC CenterPoint Energy (1) Houston Electric (1) CERC
Long-term debt, including current maturities (in millions)
Carrying amount $ 20,961 $ 8,822 $ 5,184 $ 18,609 $ 7,587 $ 4,670
Fair value 19,597 7,746 5,032 17,804 6,917 4,627
(1)Includes Securitization Bonds, as applicable.
(10) Equity Securities and Indexed Debt Securities (ZENS) (CenterPoint Energy)
(a) Equity Securities
Gains and losses on equity securities, net of transaction costs, are recorded as Gain (loss) on equity securities in CenterPoint Energy’s Statements of Consolidated Income. The following table presents unrealized gains (losses), net on equity securities owned by CenterPoint Energy for each period presented:
Year Ended December 31,
2024 2023 2022
(in millions)
AT&T Common $ 62 $ (17) $ (63)
Charter Common (40) 43 (273)
WBD Common (2) 5 23
Energy Transfer Common Units (1)
- - 95
Energy Transfer Series G Preferred Units (1)
- - (9)
Total unrealized gains (losses) on equity securities, net $ 20 $ 31 $ (227)
(1)In 2022, CenterPoint Energy completed the execution of its previously announced plan to exit the midstream sector by selling its remaining Energy Transfer Common Units and Energy Transfer Series G Preferred Units.
CenterPoint Energy and its subsidiaries hold shares of certain securities, which are classified as trading securities. Shares of AT&T Common, Charter Common and WBD Common are expected to be held to facilitate CenterPoint Energy’s ability to meet its obligation under the ZENS. The following table presented the shares held by CenterPoint Energy and their carrying value for each period presented:
Shares Held at December 31, Carrying Value at December 31,
2024 2023 2024 2023
(in millions)
AT&T Common 10,212,945 10,212,945 $ 233 $ 171
Charter Common 872,503 872,503 299 339
WBD Common 2,470,685 2,470,685 26 28
Other 3 3
Total
$ 561 $ 541
(b) ZENS
In September 1999, CenterPoint Energy issued ZENS having an original principal amount of $1.0 billion, of which $828 million remained outstanding as of December 31, 2024. Each ZENS is exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares attributable to such note. The number and identity of the reference shares attributable to each ZENS are adjusted for certain corporate events. CenterPoint Energy’s reference shares for each ZENS consisted of the following as of the dates presented:
December 31, 2024 December 31, 2023
(in shares)
AT&T Common 0.7185 0.7185
Charter Common 0.061382 0.061382
WBD Common 0.173817 0.173817
CenterPoint Energy pays interest on the ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the reference shares attributable to the ZENS. The principal amount of the ZENS is subject to increases or decreases to the extent that the annual yield from interest and cash dividends on the reference shares attributable to the ZENS is less than or more than 2.309%. The adjusted principal amount is defined in the ZENS instrument as “contingent principal.” As of December 31, 2024, the ZENS, having an original principal amount of $828 million and a contingent principal amount of $9 million, were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of the reference shares attributable to the ZENS. As of December 31, 2024, the market value of such shares was approximately $558 million, which would provide an exchange amount of $640 for each $1,000 original principal amount of ZENS. At maturity of the ZENS in 2029, CenterPoint Energy will be obligated to pay in cash the higher of the contingent principal amount of the ZENS or an amount based on the then-current market value of the reference shares, which will include any additional publicly-traded securities distributed with respect to the current reference shares prior to maturity.
The ZENS obligation is bifurcated into a debt component and a derivative component (the holder’s option to receive the appreciated value of the reference shares at maturity). The bifurcated debt component accretes through interest charges annually up to the contingent principal amount of the ZENS in 2029. Such accretion will be reduced by annual cash interest payments, as previously described. The derivative component is recorded at fair value and changes in the fair value of the derivative component are recorded as Gain (loss) on indexed debt securities in CenterPoint Energy’s Statements of Consolidated Income. Changes in the fair value of the ZENS-Related Securities held by CenterPoint Energy are expected to substantially offset changes in the fair value of the derivative component of the ZENS.
The following table provides summarized financial information related to CenterPoint Energy’s investment in ZENS-Related Securities and each component of CenterPoint Energy’s ZENS obligation for the periods presented:
ZENS-Related
Securities Debt
Component
of ZENS Derivative
Component
of ZENS
(in millions)
Balance as of December 31, 2021 $ 820 $ 10 $ 903
Accretion of debt component of ZENS - 17 -
2% interest paid - (17) -
Distribution to ZENS holders - (3) -
Gain on indexed debt securities - - (325)
Loss on ZENS-Related Securities (313) - -
Balance as of December 31, 2022 507 7 578
Accretion of debt component of ZENS - 17 -
2% interest paid - (17) -
Distribution to ZENS holders - (2) -
Loss on indexed debt securities - - 27
Gain on ZENS-Related Securities 31 - -
Balance as of December 31, 2023 538 5 605
Accretion of debt component of ZENS - 16 -
2% interest paid - (17) -
Distribution to ZENS holders - (2) -
Loss on indexed debt securities - - 14
Gain on ZENS-Related Securities 20 - -
Balance as of December 31, 2024 $ 558 $ 2 $ 619
(11) Equity (CenterPoint Energy)
Dividends Declared and Paid (CenterPoint Energy)
CenterPoint Energy’s dividends declared and dividends paid during 2024, 2023 and 2022 are presented below:
Dividends Declared Per Share Dividends Paid Per Share
2024 2023 2022 2024 2023 2022
Common Stock $ 0.830 $ 0.780 $ 0.720 $ 0.810 $ 0.770 $ 0.700
Series A Preferred Stock (1) $ - $ 30.625 $ 61.250 $ - $ 61.250 $ 61.250
(1)All of the outstanding shares of Series A Preferred Stock were redeemed during 2023 as further described below.
Common Stock (CenterPoint Energy)
(a) Underwritten Offering
On August 9, 2024, CenterPoint Energy issued 9,754,194 shares of Common Stock in an underwritten public offering at a price of $25.36 per share, for net proceeds of $247 million after deducting issuance costs. The proceeds from the offering were used for the repayment of a portion of CenterPoint Energy’s then-outstanding commercial paper.
(b) Equity Distribution Agreement
On January 10, 2024, CenterPoint Energy entered into an Equity Distribution Agreement with certain financial institutions with respect to the offering and sale from time to time of shares of Common Stock, having an aggregate gross sales price of up to $500 million. Sales of Common Stock may be made by any method permitted by applicable law and deemed to be an “at the market offering” as defined in Rule 415 of the Securities Act of 1933, as amended. CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations. 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. During the year ended
December 31, 2024, CenterPoint Energy issued 8,790,848 shares of Common Stock through the ATM Managers under the Equity Distribution Agreement, representing aggregate cash proceeds of $247 million, which was net of compensation paid by CenterPoint Energy to the ATM Managers of $2 million. As of December 31, 2024, CenterPoint Energy had not entered into any forward sale agreements under the at-the-market program. Additionally, as of December 31, 2024, CenterPoint Energy had $250 million of remaining capacity available under the program.
Series A Preferred Stock (CenterPoint Energy)
Liquidation Preference Per Share
Share Outstanding as of December 31,
Outstanding Value as of December 31,
2024 2023 2022 2024 2023 2022
(in millions, except shares and per share amount)
Series A Preferred Stock (1) $ 1,000 - - 800,000 $ - $ - $ 790
(1)All of the outstanding shares of Series A Preferred Stock were redeemed during 2023 as further described below.
Income Allocated to Series A Preferred Shareholders
Year Ended December 31,
2024 2023 2022
(in millions)
Series A Preferred Stock $ - $ 50 $ 49
Prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023, as further described below, the aggregate liquidation value of the Series A Preferred Stock was $800 million with a per share liquidation value of $1,000. The Series A Preferred Stock was redeemable at CenterPoint Energy’s election on or after September 1, 2023, for cash at a redemption price of $1,000 per share, plus any accumulated and unpaid dividends thereon to, but excluding, the redemption date.
Dividends. The Series A Preferred Stock accrued cumulative dividends, calculated as a percentage of the stated amount per share, at a fixed annual rate of 6.125% per annum to be paid in cash if, when and as declared. If declared, dividends were payable semi-annually in arrears on each March 1 and September 1, beginning on March 1, 2019. Cumulative dividends earned during the applicable periods are presented on CenterPoint Energy’s Statements of Consolidated Income as Preferred stock dividend requirement.
Redemption of Series A Preferred Stock. On September 1, 2023, CenterPoint Energy redeemed all 800,000 outstanding shares of Series A Preferred Stock, in whole for cash at a redemption price of $1,000.
Accumulated Other Comprehensive Income (Loss) (CenterPoint Energy, Houston Electric and CERC)
Changes in accumulated other comprehensive income (loss) are as follows for the periods presented:
Year Ended December 31,
2024 2023
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Beginning Balance $ (35) $ - $ 16 $ (31) $ - $ 16
Other comprehensive income (loss) before reclassifications:
Remeasurement of pension and other postretirement plans 16 (1) 2 (8) - -
Net deferred gain from cash flow hedges 4 - - 1 - -
Amounts reclassified from accumulated other comprehensive income (loss):
Prior service cost (benefit) (1) 1 - 1 1 - (2)
Actuarial losses (gain) (1) 2 - (2) 1 - 2
Reclassification of deferred gain from cash flow hedges realized in net income
(1) - - - - -
Tax benefit (expense) (4) - - 1 - -
Other comprehensive income (loss) 18 (1) 1 (4) - -
Ending Balance $ (17) $ (1) $ 17 $ (35) $ - $ 16
(1)Amounts are included in the computation of net periodic cost and are reflected in Other income (expense), net in each of the Registrants’ respective Statements of Consolidated Income.
(12) Short-term Borrowings and Long-term Debt
Short-term Borrowings and Long-term Debt: As of December 31, 2024 and 2023, the Registrants had the following short-term borrowings and long-term debt outstanding:
December 31, 2024 December 31, 2023
Long-Term Current (1) Long-Term Current (1)
(in millions)
CenterPoint Energy:
ZENS due 2029 (2) $ - $ 2 $ - $ 5
CenterPoint Energy senior notes 1.45% to 5.25% due 2026 to 2049
3,950 - 3,250 850
CenterPoint Energy junior subordinated notes 6.70% to 7.00% due 2055
1,300 - - -
CenterPoint Energy pollution control bonds 5.125% due 2028 (3)
68 - 68 -
CenterPoint Energy commercial paper (4) 382 - 1,036 -
SIGECO first mortgage bonds 3.450% to 6.00% due 2025 to 2055 (5)
944 41 825 22
SIGECO securitization bonds 5.026% to 5.172% due 2036 to 2041 (6)
311 13 324 17
Unamortized debt issuance costs (48) - (35) -
Unamortized discount and premium, net (6) - (5) -
Houston Electric debt (see details below) 8,322 500 7,426 161
CERC debt (see details below) 5,174 10 4,670 4
Total CenterPoint Energy debt $ 20,397 $ 566 $ 17,559 $ 1,059
Houston Electric:
Short Term Borrowings:
Term loan
$ - $ 500 $ - $ -
Long-term debt:
General mortgage bonds 2.35% to 6.95% due 2026 to 2053 (7)
$ 8,412 $ - $ 7,512 $ -
Other 1 - 1 -
Bond Company IV:
Transition bonds 3.028% due 2024
- - - 161
Unamortized debt issuance costs (62) - (59) -
Unamortized discount and premium, net (29) - (28) -
Total Houston Electric debt $ 8,322 $ 500 $ 7,426 $ 161
CERC (8):
Short-term borrowings:
Inventory financing (9) $ - $ - $ - $ 4
Long-term debt:
Senior notes 1.75% to 6.625% due 2026 to 2047
$ 4,520 $ - $ 4,120 $ -
Indiana Gas senior notes 6.34% to 7.08% due 2025 to 2029
86 10 96 -
Commercial paper (4) 599 - 484 -
Unamortized debt issuance costs (31) - (31) -
Unamortized discount and premium, net - - 1 -
Total CERC debt $ 5,174 $ 10 $ 4,670 $ 4
(1)Includes amounts due or exchangeable within one year of the date noted.
(2)CenterPoint Energy’s ZENS obligation is bifurcated into a debt component and an embedded derivative component. For additional information regarding ZENS, see Note 10(b). As ZENS are exchangeable for cash at any time at the option of the holders, these notes are classified as a current portion of long-term debt.
(3)These pollution control bonds were secured by general mortgage bonds of Houston Electric as of December 31, 2024 and 2023 and are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations.
(4)Commercial paper issued by CenterPoint Energy and CERC Corp. has maturities up to 60 days and 30 days, respectively, and are backstopped by the respective issuer’s long-term revolving credit facility. Commercial paper is classified as long-term because the termination date of the facility that backstops the commercial paper is more than one year from the balance sheet date.
(5)The first mortgage bonds issued by SIGECO subject SIGECO’s properties to a lien under the related mortgage indenture as further discussed below.
(6)Scheduled final payment dates are November 15, 2036 and May 15, 2041. The SIGECO Securitization Bonds will be repaid over time through a securitization charge imposed on retail electric customers in SIGECO’s service territory.
(7)The general mortgage bonds issued by Houston Electric subject Houston Electric’s properties to a lien under the General Mortgage as further discussed below.
(8)Issued by CERC Corp.
(9)Represents AMA transactions accounted for as an inventory financing.
Debt Transactions
Debt Issuances. During 2024, the following debt instruments were issued or incurred:
Registrant Issuance Date Debt Instrument Aggregate Principal Amount Interest Rate Maturity Date
(in millions, except for interest rates)
Houston Electric (1) February 2024 General Mortgage Bonds $ 400 5.15% 2034
Houston Electric (2)
June 2024 Term Loan 500 SOFR (9) + 1.00%
Houston Electric (3)
October 2024 General Mortgage Bonds 500 5.05% 2035
Total Houston Electric 1,400
CERC (4)
June 2024 Senior Notes 400 5.40% 2034
Total CERC 400
CenterPoint Energy (5)
May 2024 Senior Notes 700 5.40% 2029
CenterPoint Energy (6)
August 2024 First Mortgage Bonds
100 5.18% 2034
CenterPoint Energy (6)
August 2024 First Mortgage Bonds
60 5.28% 2036
CenterPoint Energy (7)
August 2024 Junior Subordinated Notes
400 7.00% 2055
CenterPoint Energy (7)
August 2024 Junior Subordinated Notes
400 6.85% 2055
CenterPoint Energy (8)
October 2024 Junior Subordinated Notes
500 6.70% 2055
Total CenterPoint Energy $ 3,960
(1)Total proceeds from Houston Electric’s February 2024 issuance of general mortgage bonds, net of transaction expenses and fees, were approximately $395 million, which were used for general limited liability company purposes, including capital expenditures and working capital purposes.
(2)On June 28, 2024, Houston Electric borrowed $100 million aggregate principal amount available under the term loan agreement. In September 2024, Houston Electric borrowed $200 million aggregate principal amount available under the term loan agreement. In November 2024, Houston Electric requested additional commitments under the term loan agreement and borrowed $200 million under the term loan agreement. Houston Electric has used the proceeds thereof for working capital purposes to support liquidity needs from the May 2024 Storm Events and general limited liability company purposes.
(3)Total net proceeds from Houston Electric’s October 2024 issuance of general mortgage bonds, net of transaction expenses and fees, were approximately $494 million, which were used for general limited liability company purposes, including capital expenditures and working capital purposes.
(4)Total proceeds from CERC’s June 2024 issuance of senior notes, net of transaction expenses and fees, were approximately $396 million which were used for general corporate purposes, including the repayment of a portion of CERC’s outstanding commercial paper.
(5)Total proceeds from CenterPoint Energy’s May 2024 issuance of senior notes, net of transaction expenses and fees, were approximately $693 million which were used for general corporate purposes including the redemption of $350 million aggregate principal amount of CenterPoint Energy’s outstanding floating rate senior notes due 2024 and the repayment of a portion of CenterPoint Energy’s outstanding commercial paper.
(6)Issued by SIGECO. Total proceeds from SIGECO’s August 2024 issuance of first mortgage bonds, net of transaction expenses and fees, of approximately $159 million were used for general corporate purposes, including repaying short-term debt and long-term debt at maturity or otherwise. See Note 20 for additional information.
(7)Total proceeds from CenterPoint Energy’s August 2024 issuance of junior subordinated notes, net of transaction expenses and fees, were approximately $790 million, which were used for general corporate purposes, including the
redemption of $500 million aggregate principal amount of CenterPoint Energy’s outstanding 2.50% senior notes due 2024 and the repayment of a portion of CenterPoint Energy’s outstanding commercial paper.
(8)Total proceeds from CenterPoint Energy’s October 2024 issuance of junior subordinated notes, net of transaction expenses and fees, were approximately $494 million, which were used for general company purposes including the repayment of a portion of CenterPoint Energy’s outstanding commercial paper.
(9)The borrowings under the term loan agreement bear interest at Houston Electric’s option, at a rate equal to either (i) Term SOFR (as defined in the term loan agreement), which includes an adjustment of 0.10% per annum plus a margin of 1.0%, or (ii) the Alternate Base Rate (as defined in the term loan agreement)
Junior Subordinated Notes. As described in the table above, in August 2024, CenterPoint Energy issued $400 million aggregate principal amount of Junior Subordinated Series A Notes and $400 million aggregate principal amount of Junior Subordinated Series B Notes. Interest on the August Junior Subordinated Notes accrues from August 14, 2024 and is payable semiannually in arrears on February 15 and August 15 of each year, beginning on February 15, 2025, and maturing on February 15, 2055. The Junior Subordinated Series A Notes bear interest (i) from and including August 14, 2024 to, but excluding, February 15, 2030 at the rate of 7.000% per annum and (ii) from and including February 15, 2030, during each five-year period following February 15, 2030, at a rate per annum equal to the Five-Year Treasury Rate (as defined in the Junior Subordinated Notes Indenture) as of two business days prior to the beginning of the applicable Junior Subordinated Series A Interest Reset Period plus a spread of 3.254%, with such rate per annum to be reset on each five-year anniversary of February 15, 2030. The Junior Subordinated Series B Notes bear interest (i) from and including August 14, 2024, but excluding, February 15, 2035 at the rate of 6.850% per annum and (ii) from and including February 15, 2035, during each five-year period following February 15, 2035, at a rate per annum equal to the Five-Year Treasury Rate (as defined in the Junior Subordinated Notes Indenture) as of two business days prior to the beginning of the applicable Junior Subordinated Series B Interest Reset Period plus a spread of 2.946%, with such rate per annum to be reset on each five-year anniversary of February 15, 2035.
As described in the table above, in October 2024, CenterPoint Energy issued $500 million aggregate principal amount of Junior Subordinated Series C Notes. Interest on the Junior Subordinated Series C Notes accrues from October 31, 2024 and is payable semi-annually in arrears on May 15 and November 15 of each year, beginning on May 15, 2025, and maturing on May 15, 2055. The Junior Subordinated Series C Notes bear interest (i) from and including October 31, 2024 to, but excluding May 15, 2030 at the rate of 6.700% per annum and (ii) from and including May 15, 2030, during each five-year period following May 15, 2030 at a rate per annum equal to the Five-Year Treasury Rate (as defined in the Junior Subordinated Notes Indenture) as of two business days prior to the beginning of the applicable Junior Subordinated Series C Interest Reset Period plus a spread of 2.586%, with such rate per annum to be reset on each five-year anniversary of May 15, 2030.
So long as no event of default (as defined in the prospectus supplement relating to the offering of the Junior Subordinated Notes) with respect to a given series of Junior Subordinated Notes has occurred and is continuing, CenterPoint Energy may, at its option, defer interest payments on such series of Junior Subordinated Notes, from time to time, for one or more deferral periods of up to 20 consecutive semiannual interest payment periods, except that no such optional deferral period (as defined in the prospectus supplement relating to the offering of the Junior Subordinated Notes) may extend beyond the final maturity date of such series of Junior Subordinated Notes or end on a day other than the day immediately preceding an interest payment date.
During any optional deferral period, CenterPoint Energy (and its majority-owned subsidiaries, as applicable) will not (subject to certain exceptions as described in the Junior Subordinated Notes Indenture): (i) declare or pay any dividends or distributions on any of CenterPoint Energy’s capital stock; (ii) redeem, purchase, acquire or make a liquidation payment with respect to any of CenterPoint Energy’s capital stock; (iii) pay any principal, interest (to the extent such interest is deferrable) or premium on, or repay, repurchase or redeem any of CenterPoint Energy’s indebtedness that ranks equally with or junior to the Junior Subordinated Notes in right of payment (including debt securities of other series, such as the other series of the Junior Subordinated Notes issued); or (iv) make any payments with respect to any guarantees by CenterPoint Energy of any indebtedness if such guarantees rank equally with or junior to the Junior Subordinated Notes in right of payment.
The Junior Subordinated Notes are CenterPoint Energy’s unsecured obligations and rank junior and subordinate in right of payment to the prior payment in full of CenterPoint Energy’s existing and future Senior Indebtedness (as defined in the Junior Subordinated Notes Indenture).
Convertible Senior Notes. Interest on the Convertible Notes is payable semiannually in arrears on February 15 and August 15 of each year, beginning on February 15, 2024. The Convertible Notes will mature on August 15, 2026, unless earlier converted or repurchased by CenterPoint Energy in accordance with their terms.
Prior to the close of business on the business day immediately preceding May 15, 2026, the Convertible Notes are convertible only under certain conditions. On or after May 15, 2026 until the close of business on the second scheduled trading
day immediately preceding the maturity date, holders of the Convertible Notes may convert all or any portion of their Convertible Notes at any time at the conversion rate then in effect, irrespective of the conditions. CenterPoint Energy may not redeem the Convertible Notes prior to the maturity date and no sinking fund is provided for the Convertible Notes.
Upon conversion of the Convertible Notes, CenterPoint Energy will pay cash up to the aggregate principal amount of the Convertible Notes to be converted and pay or deliver, as the case may be, cash, shares of Common Stock, or a combination of cash and shares of Common Stock, at CenterPoint Energy’s election, in respect of the remainder, if any, of CenterPoint Energy’s conversion obligation in excess of the aggregate principal amount of the Convertible Notes being converted. The conversion rate for the Convertible Notes is initially 27.1278 shares of Common Stock per $1,000 principal amount of Convertible Notes (equivalent to an initial conversion price of approximately $36.86 per share of Common Stock). The initial conversion price of the Convertible Notes represents a premium of approximately 25.0% over the last reported sale price of the Common Stock on the NYSE on August 1, 2023. Initially, a maximum of 33,909,700 shares of Common Stock may be issued upon conversion of the Convertible Notes based on the initial maximum conversion rate of 33.9097 shares of Common Stock per $1,000 principal amount of Convertible Notes. The conversion rate will be subject to adjustment in some events (as described in the Convertible Notes Indenture) but will not be adjusted for any accrued and unpaid interest.
In addition, following certain corporate events that occur prior to the maturity date of the Convertible Notes, CenterPoint Energy will, in certain circumstances, increase the conversion rate for a holder of Convertible Notes who elects to convert its Convertible Notes in connection with such a corporate event. If CenterPoint Energy undergoes a fundamental change (as defined in the Convertible Notes Indenture), holders of the Convertible Notes may require CenterPoint Energy to repurchase for cash all or any portion of their Convertible Notes at a fundamental change repurchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest to, but excluding, the fundamental change repurchase date.
The Convertible Notes are senior unsecured obligations of CenterPoint Energy and rank senior in right of payment to any of CenterPoint Energy’s indebtedness that is expressly subordinated in right of payment to the Convertible Notes; equal in right of payment to any of CenterPoint Energy’s unsecured indebtedness that is not so subordinated; effectively junior in right of payment to any of CenterPoint Energy’s secured indebtedness it may incur in the future to the extent of the value of the assets securing such future secured indebtedness; and structurally junior to all indebtedness and other liabilities (including trade payables but excluding intercompany obligations and liabilities of a type not required to be reflected on a balance sheet of such subsidiaries in accordance with generally accepted accounting principles) of CenterPoint Energy’s subsidiaries.
Debt Repayments and Redemptions. During 2024, the following debt instruments were repaid at maturity or redeemed prior to maturity:
Registrant Repayment/Redemption Date Debt Instrument Aggregate Principal Interest Rate Maturity Date
(in millions)
CenterPoint Energy (1)
March 2024 First Mortgage Bonds $ 22 3.50% 2024
CenterPoint Energy (2)
May 2024 Senior Notes
350 SOFR + 0.65%
CenterPoint Energy (3)
September 2024 Senior Notes 500 2.50% 2024
Total CenterPoint Energy $ 872
(1) On February 6, 2024, SIGECO provided notice of redemption and on March 1, 2024, SIGECO paid down the outstanding principal of $22 million aggregate principal amount of SIGECO’s outstanding first mortgage bonds due 2024 at a redemption price equal to 100% of the principal amount of the first mortgage bonds to be redeemed plus accrued and unpaid interest thereon, if any, to, but excluding, the redemption date.
(2) On May 13, 2024, CenterPoint Energy redeemed $350 million aggregate principal amount of its outstanding floating rate senior notes due 2024 at a redemption price equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest thereon.
(3) In September 2024, CenterPoint Energy redeemed $500 million aggregate principal amount of its outstanding 2.50% senior notes due 2024 at a redemption price equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest thereon.
CenterPoint Energy and Houston Electric recorded the following losses on early extinguishment of debt, including make-whole premiums and recognition of deferred debt related costs, in Interest expense and other finance charges on their respective Statements of Consolidated Income unless specified otherwise:
Year Ended December 31,
2024 2023 2022
(in millions)
CenterPoint Energy (1) $ - $ 11 $ 47
Houston Electric (2) - - 2
(1) The loss on early extinguishment of debt at CenterPoint Energy during 2023 was recorded as a regulatory asset.
(2) The loss on early extinguishment of debt at Houston Electric during 2022 was recorded as a regulatory asset.
Securitization Bonds. As of December 31, 2024, CenterPoint Energy, Houston Electric and SIGECO had special purpose subsidiaries including the Bond Companies and the SIGECO Securitization Subsidiary, which are consolidated. The consolidated special purpose subsidiaries are wholly-owned, bankruptcy remote entities that were formed solely for the purpose of securitizing transition property or facilitating 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 through the issuance of securitization bonds and activities incidental thereto. The Securitization Bonds issued by Bond Company IV are payable only through the imposition and collection of transition charges, as defined in the Texas Public Utility Regulatory Act, which are irrevocable, non-bypassable charges to provide recovery of authorized qualified costs. The SIGECO Securitization Bonds are payable only through the imposition of securitization charges payable by SIGECO’s retail electric customers, which are non-bypassable charges to provide recovery of the qualified costs of SIGECO authorized by the IURC order. CenterPoint Energy, Houston Electric and SIGECO have no payment obligations in respect of the Securitization Bonds issued by Bond Company IV or the SIGECO Securitization Bonds other than to remit the applicable transition or securitization charges they collect as set forth in servicing agreements among Houston Electric, the Bond Companies, SIGECO, the SIGECO Securitization Subsidiary and other parties. Each special purpose entity is the sole owner of the right to impose, collect and receive the applicable transition and securitization charges securing the bonds issued by that entity. Creditors of CenterPoint Energy, Houston Electric and SIGECO have no recourse to any assets or revenues of the Bond Companies (including the transition charges) or the SIGECO Securitization Subsidiary, as applicable, and the bondholders have no recourse to the to the general credit of CenterPoint Energy, Houston Electric or SIGECO.
Credit Facilities. The Registrants had the following revolving credit facilities as of December 31, 2024:
Registrant Execution
Date Size of
Facility Draw Rate of SOFR plus (1) Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio Debt for Borrowed Money to Capital
Ratio as of December 31, 2024 (2)
Termination
Date (5)
(in millions)
CenterPoint Energy December 6, 2022 $ 2,400 1.500% 65% (3) 59.3% December 6, 2027
CenterPoint Energy (4) December 6, 2022 250 1.125% 65% 44.8% December 6, 2027
Houston Electric December 6, 2022 300 1.250% 67.5% (3) 53.3% December 6, 2027
CERC December 6, 2022 1,050 1.125% 65% 41.4% December 6, 2027
Total $ 4,000
(1)Based on credit ratings as of December 31, 2024.
(2)As defined in the revolving credit facility agreement, excluding Securitization Bonds.
(3)For CenterPoint Energy and Houston Electric, the financial covenant limit will temporarily increase to 70% if Houston Electric experiences damage from a natural disaster in its service territory and CenterPoint Energy certifies to the administrative agent that Houston Electric has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive 12-month period, all or part of which Houston Electric intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date CenterPoint Energy delivers its certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of CenterPoint Energy’s certification or (iii) the revocation of such certification.
(4)This credit facility was issued by SIGECO.
(5)See Note 20 for discussion of subsequent events associated with the revolving credit facilities.
The Registrants, as well as the subsidiaries of CenterPoint Energy discussed above, were in compliance with all financial debt covenants as of December 31, 2024.
As of December 31, 2024 and 2023, the Registrants had the following revolving credit facilities and utilization of such facilities:
December 31, 2024 December 31, 2023
Registrant Size of
Facility Loans Letters
of Credit Commercial
Paper Weighted Average Interest Rate Size of
Facility Loans Letters
of Credit Commercial
Paper Weighted Average Interest Rate
(in millions, except weighted average interest rate)
CenterPoint Energy (1) $ 2,400 $ - $ - $ 382 4.59 % $ 2,400 $ - $ - $ 1,036 5.54 %
CenterPoint Energy (2) 250 - - - - % 250 - - - - %
Houston Electric 300 - - - - % 300 - - - - %
CERC 1,050 - - 599 4.62 % 1,050 - 1 484 5.53 %
Total $ 4,000 $ - $ - $ 981 $ 4,000 $ - $ 1 $ 1,520
(1)CenterPoint Energy’s and CERC’s outstanding commercial paper generally have maturities up to 60 days and 30 days, respectively, and are backstopped by the respective issuer’s long-term revolving credit facility.
(2)This credit facility was issued by SIGECO.
Maturities. As of December 31, 2024, maturities of long-term debt through 2029, excluding the ZENS obligation and unamortized discounts, premiums and issuance costs, were as follows:
CenterPoint
Energy (1) Houston
Electric (1) CERC Securitization Bonds
(in millions)
2025 $ 564 $ 500 $ 10 $ 13
2026 2,274 300 60 14
2027 1,320 300 625 14
2028 2,063 500 1,230 15
2029 935 - 30 16
(1)These maturities include Securitization Bonds principal repayments on scheduled payment dates.
Liens. As of December 31, 2024, Houston Electric’s assets were subject to liens securing approximately $8.4 billion of general mortgage bonds outstanding under the General Mortgage, including approximately $68 million held in trust to secure pollution control bonds that mature in 2028 for which CenterPoint Energy is obligated. The general mortgage bonds that are held in trust to secure pollution control bonds are not reflected in Houston Electric’s consolidated financial statements because of the contingent nature of the obligations. Houston Electric may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. As of December 31, 2024, approximately $4.7 billion of additional general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions. No first mortgage bonds are outstanding under the M&DOT, and Houston Electric is contractually obligated to not issue any additional first mortgage bonds under the M&DOT and is undertaking actions to release the lien of the M&DOT and terminate the M&DOT.
As of December 31, 2024, SIGECO had approximately $985 million aggregate principal amount of first mortgage bonds outstanding. Generally, all of SIGECO’s real and tangible property is subject to the lien of SIGECO’s mortgage indenture which was amended and restated effective as of January 1, 2023. As of December 31, 2024, SIGECO was permitted to issue additional bonds under its mortgage indenture up to 70% of then currently unfunded property additions and approximately $899 million of additional first mortgage bonds could be issued on this basis.
Houston Electric and CERC participate in a money pool through which they can borrow or invest on a short-term basis. For additional information, see Note 18.
(13) Income Taxes
The components of the Registrants’ income tax expense (benefit) were as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
(in millions)
CenterPoint Energy
Current income tax expense (benefit):
Federal $ (17) $ 106 $ 294
State (9) 33 46
Total current expense (benefit)
(26) 139 340
Deferred income tax expense (benefit):
Federal 218 119 16
State 3 (88) 4
Total deferred expense 221 31 20
Total income tax expense $ 195 $ 170 $ 360
Houston Electric
Current income tax expense (benefit):
Federal $ 62 $ (26) $ 23
State 15 34 16
Total current expense 77 8 39
Deferred income tax expense:
Federal 60 159 86
State 1 1 -
Total deferred expense 61 160 86
Total income tax expense $ 138 $ 168 $ 125
CERC
Current income tax expense (benefit):
Federal $ 55 $ 12 $ 30
State (6) 3 28
Total current expense 49 15 58
Deferred income tax expense (benefit):
Federal 60 95 164
State (5) (136) 14
Total deferred expense (benefit) 55 (41) 178
Total income tax expense (benefit) $ 104 $ (26) $ 236
A reconciliation of income tax expense (benefit) using the federal statutory income tax rate to the actual income tax expense and resulting effective income tax rate were as follows:
Year Ended December 31,
2024 2023 2022
(in millions)
CenterPoint Energy (1) (2) (3)
Income before income taxes $ 1,214 $ 1,087 $ 1,417
Federal statutory income tax rate 21 % 21 % 21 %
Expected federal income tax expense 255 228 298
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax 25 25 46
State valuation allowance, net of federal income tax 17 - -
State law change, net of federal income tax (47) (69) -
Equity AFUDC (12) (13) (8)
Excess deferred income tax amortization (43) (44) (51)
Goodwill impairment - - 84
Sale of Energy Systems Group - 28 -
Other, net - 15 (9)
Total (60) (58) 62
Total income tax expense $ 195 $ 170 $ 360
Effective tax rate 16 % 16 % 25 %
Houston Electric (4) (5) (6)
Income before income taxes $ 684 $ 761 $ 635
Federal statutory income tax rate 21 % 21 % 21 %
Expected federal income tax expense 144 160 133
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax 12 27 13
Equity AFUDC
(5) - -
Excess deferred income tax amortization (17) (17) (18)
Other, net 4 (2) (3)
Total (6) 8 (8)
Total income tax expense $ 138 $ 168 $ 125
Effective tax rate 20 % 22 % 20 %
CERC (7) (8) (9)
Income before income taxes $ 644 $ 486 $ 961
Federal statutory income tax rate 21 % 21 % 21 %
Expected federal income tax expense 135 102 202
Increase (decrease) in tax expense resulting from:
State income tax expense, net of federal income tax 19 (40) 35
State law change, net of federal income tax (45) (66) -
State valuation allowance, net of federal income tax 17 - -
Goodwill impairment - - 30
Equity AFUDC
(4) - -
Excess deferred income tax amortization (15) (23) (28)
Other, net (3) 1 (3)
Total (31) (128) 34
Total income tax expense (benefit) $ 104 $ (26) $ 236
Effective tax rate 16 % (5) % 25 %
(1)Recognized a $47 million benefit for the impact of state apportionment changes and Louisiana statutory rate change that resulted in the remeasurement of state deferred taxes, a $43 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, a $17 million valuation allowance established against Louisiana and Mississippi NOL, since those NOLs will not be utilized due to the Louisiana and Mississippi natural gas LDC businesses sale and a $12 million benefit for the impact of AFUDC equity.
(2)Recognized a $69 million benefit for the impact of state apportionment changes that resulted in the remeasurement of state deferred taxes of the unitary group, a $44 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, a $13 million benefit for the impact of AFUDC equity, and a $28 million expense for the gain on the Energy Systems Group sale.
(3)Recognized a $51 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, an $8 million benefit for the impact of AFUDC equity, and a $84 million expense for the goodwill impairment on the Arkansas and Oklahoma Natural Gas business sale.
(4)Recognized a $17 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in Texas.
(5)Recognized a $17 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
(6)Recognized a $18 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
(7)Recognized a $45 million benefit for the impact of state apportionment changes and Louisiana statutory rate change that resulted in the remeasurement of state deferred taxes, a $17 million valuation allowance established against Louisiana and Mississippi NOL, since those NOLs will not be utilized due to the Louisiana and Mississippi natural gas LDC businesses sale, and a $15 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
(8)Recognized a $66 million benefit for the impact of state apportionment changes that resulted in the remeasurement of state deferred taxes of the unitary group, and a $23 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions.
(9)Recognized a $28 million benefit for the amortization of the net regulatory EDIT liability as decreed by regulators in certain jurisdictions, and a $30 million expense for the goodwill impairment on the Arkansas and Oklahoma Natural Gas business sale.
The tax effects of temporary differences that gave rise to significant portions of deferred tax assets and liabilities were as follows:
December 31, 2024 December 31, 2023
(in millions)
CenterPoint Energy
Deferred tax assets:
Benefits and compensation $ 126 $ 131
Regulatory liabilities 348 365
Loss and credit carryforwards 942 76
Asset retirement obligations 98 96
Other 150 124
Valuation allowance (35) (10)
Total deferred tax assets 1,629 782
Deferred tax liabilities:
Property, plant and equipment 4,384 3,580
Regulatory assets 750 401
Investment in ZENS and equity securities related to ZENS 866 788
Other 18 92
Total deferred tax liabilities 6,018 4,861
Net deferred tax liabilities $ 4,389 $ 4,079
Houston Electric
Deferred tax assets:
Benefits and compensation $ 8 $ 10
Regulatory liabilities 158 176
Loss and credit carryforward
408 -
Asset retirement obligations 9 6
Other 16 18
Total deferred tax assets 599 210
Deferred tax liabilities:
Property, plant and equipment 1,988 1,497
Regulatory assets 113 119
Total deferred tax liabilities 2,101 1,616
Net deferred tax liabilities $ 1,502 $ 1,406
CERC
Deferred tax assets:
Benefits and compensation $ 17 $ 21
Regulatory liabilities 150 145
Loss and credit carryforwards 694 276
Asset retirement obligations 82 86
Other 122 65
Valuation allowance (25) -
Total deferred tax assets 1,040 593
Deferred tax liabilities:
Property, plant and equipment 1,883 1,602
Regulatory assets 513 171
Other 14 66
Total deferred tax liabilities 2,410 1,839
Net deferred tax liabilities $ 1,370 $ 1,246
Tax Attribute Carryforwards and Valuation Allowance. As of December 31, 2024, CenterPoint Energy has federal NOL carryforwards of $3.3 billion, which have an indefinite carryforward period. As of December 31, 2024, CenterPoint Energy has federal charitable contribution carryforwards of $51 million which expire between 2029 and 2030. As of December 31, 2024, CenterPoint Energy has federal corporate alternative minimum tax carryforwards of $124 million which have an indefinite carryforward period. As of December 31, 2024, CenterPoint Energy has $2.1 billion of gross state NOL carryforwards which
expire between 2025 and 2043, and $3 million of state tax credits, net of valuation allowance, which do not expire. CenterPoint Energy reported a valuation allowance against certain state NOL and credit carryforwards because it is more likely than not that the benefit will not be realized.
As of December 31, 2024, Houston Electric has $1.7 billion of federal NOL carryforwards which have an indefinite carryforward period. As of December 31, 2024, Houston Electric has federal corporate alternative minimum tax carryforwards of $48 million which have an indefinite carryforward period.
As of December 31, 2024, CERC has federal NOL carryforwards of $2.3 billion which have an indefinite carryforward period. As of December 31, 2024, CERC has federal corporate alternative minimum tax carryforwards of $101 million which have an indefinite carryforward period. As of December 31, 2024, CERC has $1.2 billion of gross state NOL carryforwards which expire between 2025 and 2043, and $3 million of state tax credits, net of valuation allowance, which do not expire.
A reconciliation of CenterPoint Energy’s beginning and ending balance of unrecognized tax benefits, excluding interest and penalties, are as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
(in millions)
Balance, beginning of year $ 25 $ 26 $ 3
Increases related to tax positions of prior years
- - 26
Decreases related to tax positions of prior years
- - (3)
Lapse of statute of limitations
- (1) -
Balance, end of year $ 25 $ 25 $ 26
As of December 31, 2024, CenterPoint Energy reported net unrecognized tax benefits, including penalties and interest, of $32 million which were included in Other non-current liabilities in the Consolidated Balance Sheets. Included in the balance of uncertain tax positions as of December 31, 2024 were $25 million of tax benefits that, if recognized, would affect the effective tax rate. The Registrants recognize interest accrued related to unrecognized tax benefits and penalties as income tax expense. The above table does not include $7 million of accrued penalties and interest as of December 31, 2024. The Registrants believe that it is reasonably possible that there will be a $10 million decrease in unrecognized tax benefits, including penalties and interest, in the next 12 months as a result of a lapse of statutes on older exposures, a tax settlement, and/or a resolution of open audits.
Tax Audits and Settlements. Tax years through 2022 have been audited and settled with the IRS for CenterPoint Energy. For tax years 2023 and 2024, the Registrants are participants in the IRS’s Compliance Assurance Process.
(14) Commitments and Contingencies
(a) Purchase Obligations (CenterPoint Energy and CERC)
Commitments include minimum purchase obligations related to CenterPoint Energy’s and CERC’s Natural Gas reportable segment and CenterPoint Energy’s Electric reportable segment. Contracts with minimum payment obligations have various quantity requirements and durations and are not classified as non-trading derivative assets and liabilities in CenterPoint Energy’s and CERC’s Consolidated Balance Sheets as of December 31, 2024 and 2023 because these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas and coal supply commitments also include transportation contracts that do not meet the definition of a derivative.
On February 1, 2023, Indiana Electric entered into an amended and restated BTA to purchase the 191 MW Posey Solar project for a fixed purchase price over the anticipated 35-year life. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve the amended BTA. With the passage of the IRA, Indiana Electric can now pursue PTCs for solar projects. Indiana Electric filed the updated CPCN with a request that project costs, net of PTCs, be recovered in rate base, through base rates or the CECA mechanism, depending on which provides more timely recovery. On September 6, 2023, the IURC issued an order approving the CPCN. The Posey Solar project is expected to be placed in service in the second quarter of 2025. See Note 20 for additional details.
On January 11, 2023, the IURC issued an order approving the settlement agreement granting Indiana Electric a CPCN to purchase and acquire the 130 MW Pike County solar project through a BTA and approved the estimated cost. The IURC also
designated the project as a clean energy project as well as approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs exceeded the agreed upon levels in the BTA. After negotiations, Indiana Electric and the developer were not able to agree upon updated pricing. As a result, on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate the BTA, which terminated all further obligations of Indiana Electric with respect to the project.
As of December 31, 2024, CenterPoint Energy and CERC had the following undiscounted minimum purchase obligations:
CenterPoint Energy CERC
Natural Gas Supply Electric Supply (1) Other (2)
Natural Gas Supply
(in millions)
2025 $ 635 $ 83 $ 95 $ 631
2026 601 130 100 597
2027 517 135 18 513
2028 473 97 8 470
2029 459 94 2 456
Thereafter 1,566 1,303 190 1,544
Total $ 4,251 $ 1,842 $ 413 $ 4,211
(1)Related to PPAs with commitments ranging from 15 years to 25 years.
(2)Related primarily to technology hardware and software agreements.
Excluded from the table above are estimates for cash outlays from other PPAs through Indiana Electric that do not have minimum thresholds but require payment when energy is generated by the provider. Costs arising from certain of these commitments are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms.
(b) AMAs (CenterPoint Energy and CERC)
CenterPoint Energy’s and CERC’s Natural Gas businesses continue to utilize AMAs associated with their utility distribution service in Indiana, Louisiana, Minnesota, Mississippi and Texas. The AMAs have varying terms, the longest of which expires in 2029. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s Natural Gas either sells natural gas to the asset manager and agrees to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. Generally, AMAs are contracts between CenterPoint Energy’s and CERC’s Natural Gas and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, CenterPoint Energy’s and CERC’s Natural Gas agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for CenterPoint Energy’s and CERC’s Natural Gas and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s Natural Gas. CenterPoint Energy’s and CERC’s Natural Gas may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s Natural Gas has an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs. For amounts outstanding under these AMAs, see Note 12.
(c) Guarantees (CenterPoint Energy)
CenterPoint Energy recognizes guarantee obligations at fair value. CenterPoint Energy discloses parent company guarantees of a subsidiary’s obligation when that guarantee results in the exposure of a material obligation of the parent company even if the probability of fulfilling such obligation is considered remote.
On May 21, 2023, CenterPoint Energy, through Vectren Energy Services, entered into the Equity Purchase Agreement to sell Energy Systems Group. The sale closed on June 30, 2023. See Note 4 for further information.
In the normal course of business prior to the consummation of the transaction on June 30, 2023, CenterPoint Energy, primarily through Vectren, issued parent company level guarantees supporting Energy Systems Group’s obligations. When Energy Systems Group was wholly-owned by CenterPoint Energy, these guarantees did not represent incremental consolidated obligations, but rather, these guarantees represented guarantees of Energy Systems Group’s obligations to allow it to conduct business without posting other forms of assurance. For those obligations where potential exposure can be estimated, management estimates the maximum exposure under these guarantees to be approximately $465 million as of December 31, 2024 and expects the exposure to decrease pro rata. This exposure primarily relates to energy savings guarantees on federal
energy savings performance contracts. Other parent company level guarantees, certain of which do not contain a cap on potential liability, were issued prior to the sale of Energy Systems Group in support of federal operations and maintenance projects for which a maximum exposure cannot be estimated based on the nature of the projects.
Under the terms of the Equity Purchase Agreement, ESG Holdings Group must generally use reasonable best efforts to replace existing CenterPoint Energy guarantees with credit support provided by a party other than CenterPoint Energy as of and after the closing of the transaction. The Equity Purchase Agreement also requires certain protections to be provided for any damages incurred by CenterPoint Energy in relation to these guarantees not released by closing. No additional guarantees were provided by CenterPoint Energy in favor of Energy Systems Group subsequent to the closing of the sale on June 30, 2023.
While there can be no assurance that performance under any of these parent company guarantees will not be required in the future, CenterPoint Energy considers the likelihood of a material amount being incurred to be remote. CenterPoint Energy believes that, from Energy Systems Group’s inception in 1994 to the closing of the sale of Energy Systems Group on June 30, 2023, Energy Systems Group had a history of generally meeting its performance obligations and energy savings guarantees and its installed products operated effectively. CenterPoint Energy recorded no amounts on its Consolidated Balance Sheets as of December 31, 2024 and 2023 related to its obligation under the outstanding guarantees.
(d) Legal, Environmental and Other Matters
Legal Matters
Litigation Related to Hurricane Beryl. Various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl, the efforts made by Houston Electric to prepare for, and respond to, this event, including the electric service outage issues, and the procurement of TEEEF. Moreover, additional governmental and regulatory agencies and other entities may conduct such inquiries and investigations, as well. There are significant uncertainties around these inquiries and investigations and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed or changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom. Further, on January 22, 2025, a putative shareholder of CenterPoint Energy, Donel Davidson, filed a derivative petition in Harris County District Court, Texas, alleging breach of fiduciary duty and unjust enrichment on behalf of CenterPoint Energy against certain of its current and former directors and officers citing, in part, the topics of these inquiries and investigations. The action seeks to recover damages and other relief from the defendants on behalf of CenterPoint Energy. Additionally, on February 12, 2025, a second putative shareholder of CenterPoint Energy made a demand on the Board to investigate the same basic allegations raised in the derivative petition filed by Donel Davidson.
CenterPoint Energy and Houston Electric are subject to current and potential future litigation and claims arising out of Hurricane Beryl, which litigation and claims could include allegations of, among other things, personal injury, property damage, various economic losses in connection with loss of power, unlawful business practices, and others. As of December 31, 2024, three putative class actions had been filed against CenterPoint Energy and/or Houston Electric in the District Courts of Harris County, Texas, on behalf of individuals or entities who claim losses due to power outages lasting at least 48 hours as a result of Hurricane Beryl, such actions consisting of the following proposed classes: (1) all restaurants in Harris County, Galveston County, and Montgomery County; (2) all residential customers; and (3) all health, wellness, medical and beauty facilities in Harris County. These putative classes assert claims and theories of negligence, gross negligence, nuisance, fraud, and/or violation of Houston Electric’s tariff for retail delivery service, and each seeks damages in excess of $100 million for, among other things, business interruption, property damage and loss, cost of repair, loss of use and market value, lost income, nuisance, extreme mental anguish and/or punitive damages. In addition, as of December 31, 2024, two individual actions had been filed in Harris County District Courts asserting claims of negligence, negligence per se and/or gross negligence against CenterPoint Energy and Houston Electric. The plaintiffs in these actions allege personal injury and/or property damage from downed power lines and seek damages in excess of $1 million. CenterPoint Energy and Houston Electric intend to vigorously defend themselves against the lawsuits. CenterPoint Energy and its subsidiaries have general and excess liability insurance policies that provide coverage for third party bodily injury and property damage claims. Given the nature of some allegations, it is possible that the insurers could dispute coverage for some types of claims or damages that may be alleged by plaintiffs, and CenterPoint Energy has received from two insurers denials of indemnity coverage in the putative class actions based on the failure to supply exclusion. Those insurers have also reserved their rights with respect to coverage in those actions. CenterPoint Energy and Houston Electric intend to continue to pursue all available insurance coverage for all of these matters. To date, there have not been demands, quantification, disclosure or discovery of damages by any party to any of the above legal matters that are sufficient to enable CenterPoint Energy and its subsidiaries to estimate exposure. Given that, as well as the preliminary nature of the proceedings, the numerosity of parties and complexity of issues involved, and the uncertainties of
litigation, CenterPoint Energy and its subsidiaries are unable to predict the outcome or consequences of any of the foregoing matters or to estimate a range of potential losses. For more information regarding Hurricane Beryl, see Note 7.
Litigation Related to the February 2021 Winter Storm Event. Various legal proceedings are still pending against numerous entities with respect to the February 2021 Winter Storm Event, including against CenterPoint Energy, Utility Holding, Houston Electric, and CERC. Like other Texas energy companies and TDUs, CenterPoint Energy and Houston Electric have become involved in certain investigations, litigation and other regulatory and legal proceedings regarding their efforts to restore power during the storm and their compliance with NERC, ERCOT and PUCT rules and directives. Additionally, like other natural gas market participants, CERC has been named in litigation alleging gas market manipulation.
CenterPoint Energy, Utility Holding, and Houston Electric, along with hundreds of other defendants (including ERCOT, power generation companies, other TDUs, natural gas producers, REPs, and other entities) received claims and lawsuits filed by plaintiffs alleging wrongful death, personal injury, property damage and other injuries and damages. As of December 31, 2024, there were approximately 220 pending lawsuits that are consolidated in Texas state court in Harris County, Texas, as part of the MDL proceeding related to the February 2021 Winter Storm Event, and CenterPoint Energy and Houston Electric, along with numerous other entities, have been named as defendants in approximately 155 of those lawsuits. One of the lawsuits in the MDL is a putative class action on behalf of everyone who received electric power via the ERCOT grid and sustained a power outage between February 10, 2021 and February 28, 2021. Additionally, Utility Holding is currently named as a defendant in one lawsuit in which CenterPoint Energy and Houston Electric are also named as defendants.
The judge overseeing the MDL issued an initial case management order and stayed all proceedings and discovery. Per the case management order, the judge entertained dispositive motions in five representative or “bellwether” cases and, in late January 2023, issued rulings on them. The judge ruled that ERCOT has sovereign immunity as a governmental entity and dismissed the suits against it. In a subsequent opinion in an unrelated matter, the Texas Supreme Court held that ERCOT is entitled to sovereign immunity. This ruling will apply to claims against ERCOT in the MDL. The MDL judge also dismissed all claims against the natural gas defendants (which list of natural gas defendants incorrectly included Utility Holding) and the REP defendants and some causes of action against the other defendants. CenterPoint Energy expects that the claims against Utility Holding will ultimately be dismissed in light of the judge’s initial rulings. As to the TDU and generator defendants, the judge dismissed some causes of action but denied the motions to dismiss claims for negligence, gross negligence, and nuisance, which denial the TDU defendants and generator defendants asked the courts of appeals to overturn. On April 2, 2024, a three-judge panel of the Court of Appeals for the Fourteenth District of Texas issued an opinion in the TDU mandamus proceeding, granting in part and denying in part the TDUs’ mandamus request. In its opinion, the panel granted the TDUs’ mandamus request relating to the TDUs’ motion to dismiss the plaintiffs’ claims for (1) negligence, (2) negligent nuisance and (3) strict liability nuisance and ordered those claims be dismissed. The panel denied the TDUs’ mandamus request relating to the TDUs’ motion to dismiss the plaintiffs’ gross negligence and intentional nuisance claims. On May 22, 2024, the TDUs filed a mandamus petition with the Supreme Court of Texas, seeking dismissal of the remaining claims. The Supreme Court of Texas subsequently asked for briefing on the merits and, on December 20, 2024, set the TDUs’ mandamus petition for oral argument, which occurred on February 19, 2025.
In the generator mandamus proceeding that was pending in the Court of Appeals for the First District of Texas, a three-judge panel granted the generators’ mandamus request and ordered dismissal of all claims asserted against the generators’ defendants. The plaintiffs asked the entire First Court of Appeals to rehear the panel’s decision. On November 26, 2024, the First Court of Appeals denied that motion. The plaintiffs filed a petition for writ of mandamus with the Supreme Court of Texas on January 31, 2025.
The MDL judge allowed defendants (including Houston Electric) to file several additional motions on preliminary legal issues. These motions included the TDUs’ motion to dismiss under Chapter 150 of the Texas Civil Practice and Remedies Code, which was filed in one of the bellwether cases and argued that all of plaintiffs’ claims should be dismissed because the plaintiffs did not include a sufficient certificate by a qualified engineer with their petition, as required by Texas law, as well as a motion to deny class certification in the putative class action. On November 13, 2024, the MDL Court granted the TDUs’ motion to dismiss under Chapter 150, and on December 3, 2024, the plaintiffs filed a notice of appeal of that ruling. On January 8, 2025, the MDL Court denied class certification in the putative class action. Following issuance of the order denying class certification, a new lawsuit was filed on behalf of approximately 140 plaintiffs in Harris County District Court against hundreds of defendants, including CenterPoint Energy and Houston Electric. In addition, plaintiffs filed a notice of appeal of the denial of class certification on January 27, 2025. Aside from addressing certain additional preliminary legal issues, the cases remain stayed in the MDL Court. CenterPoint Energy, Utility Holding, and Houston Electric intend to vigorously defend themselves against the claims raised.
CenterPoint Energy and Houston Electric have also responded to inquiries from the Texas Attorney General and the Galveston County District Attorney’s Office, and various other regulatory and governmental entities also conducted inquiries, investigations and other reviews of the February 2021 Winter Storm Event and the efforts made by various entities to prepare for, and respond to, the event, including the electric generation shortfall issues.
In February 2023, twelve lawsuits were filed in state district court in Harris County and Tom Green County, Texas, against dozens of gas market participants in Texas, including natural gas producers, processors, pipelines, marketers, sellers, traders, gas utilities, and financial institutions. Plaintiffs named CERC as a defendant, along with “CenterPoint Energy Services, Inc.,” incorrectly identifying it as CERC’s parent company (CenterPoint Energy previously divested CenterPoint Energy Services, Inc.). One lawsuit filed in Harris County is a putative class action on behalf of two classes of electric and natural gas customers (those who experienced a loss of electricity and/or natural gas, and those who were charged securitization-related surcharges on a utility bill or were otherwise charged higher rates for electricity and/or gas during the February 2021 Winter Storm Event), potentially including millions of class members. Two other lawsuits (one filed in Harris County and one in Tom Green County) were brought by an entity that purports to be an assignee of the claims of tens of thousands of persons and entities. These, and nine other similar lawsuits filed in Harris County, generally allege that the defendants engaged in gas market manipulation and price gouging, including by intentionally withholding, suppressing, or diverting supplies of natural gas in connection with the February 2021 Winter Storm Event, Winter Storm Elliott, and other severe weather conditions, and through financial market manipulation. Plaintiffs allege that this manipulation impacted gas supply and prices as well as the market, supply, and price of electricity in Texas and caused blackouts and other damage. Plaintiffs assert claims for tortious interference with existing contract, private nuisance, and unjust enrichment, and allege a broad array of injuries and damages, including personal injury, property damage, and harm from certain costs being securitized and passed on to ratepayers. The lawsuits do not specify the amount of damages sought, but seek broad categories of actual, compensatory, statutory, consequential economic, and punitive damages; restitution and disgorgement; pre- and post-judgment interest; costs and attorneys’ fees; and other relief. All twelve lawsuits have been tagged for transfer to the existing MDL proceeding referenced above, but only three of the cases have been served against the defendants, including CERC. These gas market cases are in addition to the 220 cases noted above regarding electric market issues.
On February 2, 2024, CERC filed pleas to the jurisdiction in the three cases in which it was served; CERC also partially joined the other defendants’ motions to dismiss and additional pleas to the jurisdiction. On April 2, 2024, plaintiffs in the three served cases filed amended petitions rather than responding to pleas to the jurisdiction and motions to dismiss. Among other changes, plaintiffs in these three cases dismissed CenterPoint Energy Services, Inc., but maintained the same three causes of action as to the remaining defendants. CERC has vigorously defended itself against the claims raised, including filing updated pleas to the jurisdiction on May 17, 2024 in response to plaintiffs’ amended petitions - and will continue to do so. On August 12, 2024, plaintiffs in the putative class action filed a motion for leave to amend to add additional plaintiffs/class representatives. Defendants opposed this motion on September 20, 2024. On September 23, 2024, the MDL judge heard oral argument on CERC’s plea to the jurisdiction and defendants’ motions to dismiss and other pleas to the jurisdiction. On November 7, 2024 and November 11, 2024, the MDL judge granted defendants’ motion to dismiss and CERC’s plea to the jurisdiction in all three cases. As a result of these rulings, all claims against CERC were dismissed with prejudice. Plaintiffs have appealed these rulings, and the appeals have been assigned to the Court of Appeals for the First District of Texas. On December 4, 2024, the MDL judge denied as moot plaintiff’s motion for leave to amend to add additional plaintiffs/class representatives in the putative class action case. On January 17, 2025, the plaintiffs in the putative class action case filed an unopposed motion to dismiss their appeal, which the Court of Appeals granted on February 4, 2025, dismissing the appeal. Plaintiffs’ opening briefs in the remaining two cases are scheduled to be filed on March 28, 2025.
To date, there have not been demands, quantification, disclosure or discovery of damages by any party to any of the above legal matters that are sufficient to enable CenterPoint Energy and its subsidiaries to estimate exposure. Given that, as well as the preliminary nature of the proceedings, the numerosity of parties and complexity of issues involved, and the uncertainties of litigation, CenterPoint Energy and its subsidiaries are unable to predict the outcome or consequences of any of the foregoing matters or to estimate a range of potential losses. CenterPoint Energy and its subsidiaries have general and excess liability insurance policies that provide coverage for third party bodily injury and property damage claims. As CenterPoint Energy previously noted, given the nature of certain of the plaintiffs’ allegations, insurance coverage may not be available other than for third party bodily injury and property damage claims caused by an accident, and one of CenterPoint Energy’s insurers has reserved its rights with respect to coverage for plaintiffs’ intentional nuisance claims as well as plaintiffs’ claims in the gas market cases. CenterPoint Energy and its subsidiaries intend to continue to pursue all available insurance coverage for all of these matters.
Jefferson Parish. Several parishes and the State of Louisiana filed 42 suits under Louisiana’s State and Local Coastal Resources Management Act against hundreds of oil and gas companies seeking compensatory damages for contamination and erosion of the Louisiana coastline allegedly caused by historical oil and gas operations. One of the defendants in one of the lawsuits (filed in 2013 only by the Parish of Jefferson) is Primary Fuels, Inc., a predecessor company of CenterPoint Energy, which operated in Louisiana from 1983 to 1989. All 42 suits were removed to Louisiana federal courts twice and were stayed for several years pending the district courts’ consideration of various motions to remand and multiple appeals of remand orders. Recently, several cases involving other parishes that had been remanded to Louisiana state court have begun to resume proceedings in state court. However, as of December 31, 2024, the federal district court had not ruled on Jefferson Parish’s motion to remand to state court the lawsuit which includes Primary Fuels among the defendants.
Because of the procedurally preliminary nature of the proceedings, lack of information about both the scope of and damages for Jefferson Parish’s claim against Primary Fuels, Inc., the numerosity of parties and complexity of issues involved, and the uncertainties of litigation, CenterPoint Energy and its subsidiaries are unable to predict the outcome or consequences of this matter or to estimate a range of potential losses. CenterPoint Energy will continue to vigorously defend itself against the claims raised and pursue any and all available insurance coverage.
Environmental Matters
MGP Sites. CenterPoint Energy, CERC and their predecessors, including predecessors of Vectren, operated MGPs in the past. The costs CenterPoint Energy or CERC, as applicable, expect to incur to fulfill their respective obligations are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While CenterPoint Energy and CERC have recorded obligations for all costs which are probable and estimable, including amounts they are presently obligated to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery.
(i)Minnesota MGPs (CenterPoint Energy and CERC). With respect to certain Minnesota MGP sites, CenterPoint Energy and CERC have completed state-ordered remediation and continue state-ordered monitoring and water treatment. CenterPoint Energy and CERC recorded a liability as reflected in the table below for continued monitoring and any future remediation required by regulators in Minnesota.
(ii)Indiana MGPs (CenterPoint Energy and CERC). In the Indiana Gas service territory, the existence, location and certain general characteristics of 26 gas manufacturing and storage sites have been identified for which CenterPoint Energy and CERC may have some remedial responsibility. A remedial investigation/feasibility study was completed at one of the sites under an agreed upon order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. The remaining sites have been submitted to the IDEM’s VRP. CenterPoint Energy has also identified its involvement in five manufactured gas plant sites in SIGECO’s service territory, all of which are currently enrolled in the IDEM’s VRP. CenterPoint Energy is currently conducting some level of remedial activities, including groundwater monitoring at certain sites.
(iii)Other MGPs (CenterPoint Energy and CERC). In addition to the Minnesota and Indiana sites, the EPA and other regulators have investigated MGP sites that were owned or operated by CenterPoint Energy or CERC or may have been owned by one of their former affiliates.
Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to CenterPoint Energy’s and CERC’s share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which CenterPoint Energy and CERC believe they may have responsibility was based on remediation continuing for the minimum time frame given in the table below:
December 31, 2024
CenterPoint Energy CERC
(in millions, except years)
Amount accrued for remediation $ 13 $ 11
Minimum estimated remediation costs 8 7
Maximum estimated remediation costs 47 40
Minimum years of remediation 5 5
Maximum years of remediation 50 50
The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used.
CenterPoint Energy and CERC do not expect the ultimate outcome of these matters to have a material adverse effect on the financial condition, results of operations or cash flows of either CenterPoint Energy or CERC.
Asbestos. Some facilities owned by the Registrants or their predecessors contain or have contained asbestos insulation and other asbestos-containing materials. The Registrants are from time to time named, along with numerous others, as defendants in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos, and the Registrants anticipate that additional claims may be asserted in the future. Although their ultimate outcome cannot be predicted at this time, the Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.
CCR Rule (CenterPoint Energy). In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and a portion of the ash generated by Indiana Electric’s generating plants will continue to be reused.
Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the CCR Rule, Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. Pursuant to the CCR Rule, both the Culley East and A.B. Brown facilities were taken out of service in a timely manner per the commitments made to the EPA in the extension requests filed for both ponds. On April 24, 2019, Indiana Electric received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already completed closure activities. On August 14, 2019, Indiana Electric filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of ponded ash. This petition was subsequently approved by the IURC on May 13, 2020. On October 28, 2020, the IURC approved Indiana Electric’s ECA proceeding, which included the initiation of recovery of the federally mandated project costs.
On November 1, 2022, Indiana Electric filed for a CPCN to recover federally mandated costs associated with closure of the Culley East Pond, its third and final ash pond. Indiana Electric sought accounting and ratemaking relief for the project, and on June 8, 2023, Indiana Electric filed a revised CPCN for recovery of the federally mandated ash pond costs. On February 7, 2024 the IURC approved the federally mandated costs, both incurred and projected, of $52 million in capital costs, plus an estimated $133,000 in annual operation and maintenance expenses, for recovery through the ECA.
As of December 31, 2024, CenterPoint Energy had recorded an approximate $121 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of Indiana Electric’s generation transition plan; changing environmental regulations; and proceeds received from the settlements in a previously settled insurance proceeding. In addition to these AROs, Indiana Electric also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project.
On April 25, 2024, the EPA released its final Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities; Legacy CCR Surface Impoundments rule (CCR Legacy Rule), which was published in the federal register in May 2024. The CCR Legacy Rule requires companies to investigate previously closed impoundments that were used historically for ash disposal or locations which have had ash placed on them in amounts set forth in the CCR Legacy Rule. The Registrants have completed their preliminary review of potential sites that will require further investigation under the CCR Legacy Rule and identified certain sites in Indiana for further evaluation. During 2024, Indiana Electric recorded an approximate $11 million ARO with a corresponding increase of $11 million to Property, plant and equipment for amounts recoverable for electric generation stations that are currently in service. These estimates reflect the discounted value of future estimated capping costs for an area of historic ash placement at F.B. Culley. Indiana Electric will continue to refine the assumptions, engineering analyses and resulting cost estimates associated with this ARO and such refinement could materially impact the amount of the estimated ARO.
Clean Water Act Permitting of Groundwater and Power Plant Discharges. In April 2020, the U.S. Supreme Court issued an opinion providing that indirect discharges via groundwater or other non-point sources are subject to permitting and liability under the Clean Water Act when they are the functional equivalent of a direct discharge. On November 27, 2023, the EPA published draft guidance regarding the application of the “functional equivalent” analysis as related to permitting of certain
discharges through groundwater to surface waters. The Registrants do not currently anticipate impacts from this guidance, but groundwater monitoring continues under the CCR Rule.
In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. In February 2019, the IURC approved Indiana Electric’s Effluent Limitation Guidelines Compliance Plan for its F.B. Culley Generating Station, which was completed in compliance with the requirements of the Effluent Limitation Guidelines. On April 25, 2024, the EPA released its final Supplemental Effluent Limitation Guidelines and Standards for the Steam Electric Generating Point Source Category. The Registrants currently anticipate that they will be in compliance with the Supplemental ELG Guidelines at the Culley facility due to previous wastewater treatment upgrades.
Other Environmental. From time to time, the Registrants identify the presence of environmental contaminants during operations or on property where their predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. The Registrants have and expect to continue to remediate any identified sites consistent with state and federal legal obligations. From time to time, the Registrants have received notices, and may receive notices in the future, from regulatory authorities or others regarding status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Registrants have been, or may be, named from time to time as defendants in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Registrants do not expect these matters, either individually or in the aggregate, to have a material adverse effect on their financial condition, results of operations or cash flows.
Other Proceedings
The Registrants are involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, the Registrants are also defendants in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. The Registrants regularly analyze current information and, as necessary, provide accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. The Registrants do not expect the disposition of these matters to have a material adverse effect on the Registrants’ financial condition, results of operations or cash flows.
(15) Earnings Per Share (CenterPoint Energy)
Basic earnings per common share is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from weighted average number of common shares outstanding in the computation of basic earnings per common share. Diluted earnings per common share is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive.
Diluted earnings per common share reflects the dilutive effect of potential common shares from share-based awards. The dilutive effect of restricted stock is computed using the if-converted method, which assumes conversion of the restricted stock at the beginning of the period. The dilutive effect of restricted stock is computed using the treasury stock method, as applicable, which includes the incremental shares that would be hypothetically vested in excess of the number of shares assumed to be hypothetically repurchased with the assumed proceeds.
Diluted earnings per common share will also reflect the dilutive effect of potential common shares from the conversion of the Convertible Notes. Convertible debt in which the principal amount must be settled in cash is excluded from the calculation of diluted earnings per common share. There would be no interest expense adjustment to the numerator for the cash-settled portion of the Convertible Notes because that portion will always be settled in cash. The conversion spread value in shares will be included in diluted earnings per common share using the if-converted method if the convertible debt is in the money. The denominator of diluted earnings per common share is determined by dividing the conversion spread value of the share-settled portion of the Convertible Notes as of the reporting date by the average share price over the reporting period. For the year ended December 31, 2024, the convertible debt was not in the money; therefore, no incremental shares were assumed converted or included in the diluted earnings per common share calculation below. For further details on the Convertible Notes, see Note 12.
The following table reconciles numerators and denominators of CenterPoint Energy’s basic and diluted earnings per common share for the periods presented:
Year Ended December 31,
2024 2023 2022
(in millions, except per share and share amounts)
Numerator:
Net income $ 1,019 $ 917 $ 1,057
Less: Preferred stock dividend requirement (Note 11)
- 50 49
Income available to common shareholders - basic and diluted $ 1,019 $ 867 $ 1,008
Denominator:
Weighted average common shares outstanding - basic 643,163,000 630,947,000 629,415,000
Plus: Incremental shares from assumed conversions:
Restricted stock 974,000 2,232,000 2,931,000
Weighted average common shares outstanding - diluted 644,137,000 633,179,000 632,346,000
Earnings per Common Share:
Basic $ 1.58 $ 1.37 $ 1.60
Diluted $ 1.58 $ 1.37 $ 1.59
(16) Reportable Segments
The Registrants’ determination of reportable segments considers the strategic operating units under which its CODM manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments.
As of December 31, 2024, reportable segments by Registrant and information about each Registrant’s CODM were as follows:
CenterPoint Energy
•CenterPoint Energy’s Electric reportable segment consisted of electric transmission and distribution services in the Texas Gulf Coast area in the ERCOT region and electric transmission and distribution services primarily to southwestern Indiana and includes power generation and wholesale power operations in the MISO region.
•CenterPoint Energy’s Natural Gas reportable segment consists of (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial and industrial customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas; and (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP.
•CenterPoint Energy’s Corporate and Other category consists of 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 all of CenterPoint Energy’s business operations. CenterPoint Energy’s Corporate and Other also includes office buildings and other real estate used for business operations.
CenterPoint Energy’s CODM, the Chief Executive Officer, evaluates performance for all of its reportable segments based on segment net income. The CODM uses segment net income to allocate resources as part of the budgeting and forecasting process as well as during periodic budget-to-actual reviews.
Houston Electric
•Houston Electric’s single reportable segment consisted of electric transmission services to transmission service customers in the ERCOT region and distribution service to REPs in the Texas Gulf Coast area that includes the city of Houston.
Houston Electric’s CODM, the President and Chief Executive Officer, evaluates performance for its single reportable segment based on segment net income. The CODM uses segment net income to allocate resources as part of the budgeting and forecasting process as well as during periodic budget-to-actual reviews.
CERC
•CERC’s single reportable segment following the Restructuring consisted of (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial and industrial customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas; and (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP.
CERC’s CODM, the President and Chief Executive Officer, evaluates performance for its single reportable segment based on segment net income. The CODM uses segment net income to allocate resources as part of the budgeting and forecasting process as well as during periodic budget-to-actual reviews.
Expenditures for long-lived assets include property, plant and equipment. Intersegment sales are eliminated in consolidation, except as described in Note 4.
Financial data for reportable segments is as follows:
CenterPoint Energy
Year Ended December 31, 2024
Electric
Natural Gas
Corporate and Other
Total Reportable Segments
Eliminations
Total
(in millions)
Revenues from external customers
$ 4,590 $ 4,048 $ 5 $ 8,643 $ - $ 8,643
Intersegment revenues
- 2 - 2 (2) -
Utility natural gas, fuel and purchased power 198 1,520 (1) 1,717 (2) 1,715
Non-utility cost of revenues, including natural gas - 3 - 3 - 3
Operation and maintenance expenses 2,072 881 (4) 2,949 - 2,949
Depreciation and amortization 877 542 20 1,439 - 1,439
Taxes other than income taxes 304 237 6 547 - 547
Interest expense 372 207 286 865 (27) 838
Income tax expense (benefit) 157 108 (70) 195 - 195
Interest income (1) (18) (2) (14) (34) 27 (7)
Other income, net (2) (43) (12) - (55) - (55)
Net income (loss)
$ 671 $ 566 $ (218) $ 1,019 $ - $ 1,019
Year Ended December 31, 2023
Electric Natural Gas Corporate and Other Total Reportable Segments
Eliminations
Total
(in millions)
Revenues from external customers $ 4,290 $ 4,276 $ 130 $ 8,696 $ - $ 8,696
Intersegment revenues - 3 - 3 (3) -
Utility natural gas, fuel and purchased power 176 1,888 - 2,064 (3) 2,061
Non-utility cost of revenues, including natural gas - 3 96 99 - 99
Operation and maintenance expenses 1,880 949 21 2,850 - 2,850
Depreciation and amortization 872 513 16 1,401 - 1,401
Taxes other than income taxes 272 245 8 525 - 525
Interest expense 303 188 264 755 (54) 701
Income tax expense (benefit) 189 (25) 6 170 - 170
Interest income (1) (19) (10) (34) (63) 54 (9)
Other expense (income), net (2)
(37) (5) 23 (19) - (19)
Net income (loss) $ 654 $ 533 $ (270) $ 917 $ - $ 917
Year Ended December 31, 2022
Electric Natural Gas Corporate and Other Total Reportable Segments
Eliminations
Total
(in millions)
Revenues from external customers $ 4,108 $ 4,946 $ 267 $ 9,321 $ - $ 9,321
Utility natural gas, fuel and purchased power 222 2,665 - 2,887 - 2,887
Non-utility cost of revenues, including natural gas - 4 200 204 - 204
Operation and maintenance expenses 1,864 919 50 2,833 - 2,833
Depreciation and amortization 793 466 29 1,288 - 1,288
Taxes other than income taxes 275 261 7 543 - 543
Interest expense 235 137 214 586 (62) 524
Income tax expense (benefit) 147 243 (30) 360 - 360
Interest income (1) (4) (2) (60) (66) 62 (4)
Other income, net (2) (27) (239) (105) (371) - (371)
Net income (loss) $ 603 $ 492 $ (38) $ 1,057 $ - $ 1,057
(1) Interest income from Securitization Bonds of $3 million, $4 million, and less than $1 million for the years ended December 31, 2024, 2023 and 2022, respectively, is included in Other income (expense), net on CenterPoint Energy’s Statements of Consolidated Income.
(2) Other income (expense), net primarily includes AFUDC equity, non-service cost for pension and postretirement benefits, Gain (loss) on equity securities, Gain (loss) on indexed debt securities and Gain (loss) on sale.
Total Assets Expenditures for Long-lived Assets
As of December 31,
Year Ended December 31,
2023 2024 2023 2022
(in millions)
Electric $ 23,936 $ 21,089 $ 3,099 $ 2,660 $ 2,611
Natural Gas 18,583 17,429 1,524 1,697 1,697
Corporate and Other, net of eliminations (1) 1,249 1,197 26 13 107
Continuing Operations 43,768
39,715 4,649 4,370 4,415
Divestitures (2)
- - - - 3
Consolidated $ 43,768 $ 39,715 $ 4,649 $ 4,370 $ 4,418
(1)Total assets included pension and other postemployment-related regulatory assets of $384 million and $385 million as of December 31, 2024 and 2023, respectively.
(2)For further information regarding CenterPoint Energy’s and CERC’s divestitures, see Note 4.
Houston Electric
Houston Electric consists of a single reportable segment. For financial data related to income and expenses for the single reportable segment, see Houston Electric’s Statements of Consolidated Income. For financial data related to segment total assets, see Houston Electric’s Consolidated Balance Sheets. Financial data related to interest income and expenditures for long-lived assets is as follows:
Year Ended December 31,
2024 2023 2022
(in millions)
Interest income (1)
$ 16 $ 14 $ 3
Expenditures for long-lived assets
2,738 2,309 2,302
(1)Reflected in Other income (expense), net on Houston Electric’s Statements of Consolidated Income.
CERC
CERC consists of a single reportable segment. For financial data related to income and expenses for the single reportable segment, see CERC’s Statements of Consolidated Income. For financial data related to segment total assets, see CERC’s Consolidated Balance Sheets. Financial data related to interest income and expenditures for long-lived assets is as follows:
Year Ended December 31,
2024 2023 2022
(in millions)
Interest income (1)
$ 2 $ 10 $ 3
Expenditures for long-lived assets
1,485 1,568 1,616
(1)Reflected in Other income (expense), net on CERC’s Statements of Consolidated Income.
Major Customers (Houston Electric)
Houston Electric’s revenues from major external customers are as follows:
Year Ended December 31,
2024 2023 2022
(in millions)
Affiliates of NRG $ 1,169 $ 1,106 $ 1,046
Affiliates of Vistra Energy Corp. 605 539 489
Revenues by Products and Services
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Electric delivery $ 3,963 $ 3,939 $ - $ 3,701 $ 3,677 $ - $ 3,438 $ 3,412 $ -
Retail electric sales 622 - - 569 - - 630 - -
Wholesale electric sales 4 - - 20 - - 40 - -
Retail gas sales 3,837 - 3,716 4,078 - 3,951 4,759 - 4,613
Gas transportation 11 - 11 11 - 11 12 - 12
Energy products and services 206 - 198 317 - 187 442 - 175
Total $ 8,643 $ 3,939 $ 3,925 $ 8,696 $ 3,677 $ 4,149 $ 9,321 $ 3,412 $ 4,800
(17) Supplemental Disclosure of Cash Flow and Balance Sheet Information
Supplemental Disclosure of Cash Flow Information
The tables below provide supplemental disclosure of cash flow information for the periods presented:
2024 2023 2022
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Cash Payments (Refunds):
Interest, net of capitalized interest $ 805 $ 321 $ 190 $ 664 $ 287 $ 175 $ 480 $ 223 $ 104
Income tax payments (refunds), net (1) (9) 26 3 215 12 115 421 142 37
Non-cash transactions:
Accounts payable related to capital expenditures
467 381 103 246 166 74 335 168 139
ROU assets obtained in exchange for lease liabilities (2) 18 - 13 3 1 - 7 6 -
(1) CenterPoint Energy’s $215 million income tax payments in 2023 were attributable to recovery of extraordinary gas costs incurred in the February 2021 Winter Storm through the Railroad Commission ordered securitization.
(2) Excludes ROU assets obtained through prepayment of the lease liabilities. See Note 19.
The table below provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the amount reported in the Statements of Consolidated Cash Flows for the periods presented:
December 31, 2024 December 31, 2023
CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC
(in millions)
Cash and cash equivalents (1) $ 24 $ 14 $ 2 $ 90 $ 76 $ 1
Restricted cash included in Prepaid expenses and other current assets (2) 6 - - 19 13 -
Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows $ 30 $ 14 $ 2 $ 109 $ 89 $ 1
(1)Cash and cash equivalents related to VIEs as of December 31, 2024 and 2023 included $21 million and $90 million, respectively, at CenterPoint Energy and $14 million and $76 million, respectively, at Houston Electric.
(2)Restricted cash primarily related to accounts established by CenterPoint Energy and Houston Electric in connection with the issuance of the Securitization Bonds to collateralize the Securitization Bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the Securitization Bonds.
Supplemental Disclosure of Balance Sheet Information
Included in other current liabilities on CERC’s Consolidated Balance Sheets as of December 31, 2024 and 2023 was $98 million and $118 million, respectively, of credits related to customers on budget billing programs. Included in other current liabilities on Houston Electric’s Consolidated Balance Sheets as of December 31, 2024 and 2023 was $85 million and $47 million, respectively, of builder deposits.
(18) Related Party Transactions (Houston Electric and CERC)
Houston Electric and CERC participate in CenterPoint Energy’s money pool through which they 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 table below summarizes CenterPoint Energy money pool activity for the periods presented:
December 31, 2024 December 31, 2023
Houston Electric CERC Houston Electric CERC
(in millions, except interest rates)
Money pool investments (1)
$ 368 $ - $ 238 $ 1
Weighted average interest rate 4.65 % - % 5.59 % 5.59 %
(1)Included in Accounts and notes receivable-affiliated companies in Houston Electric’s and CERC’s respective Consolidated Balance Sheets as of December 31, 2024 and 2023, as applicable.
Houston Electric and CERC affiliate-related transactions were as follows:
Year Ended December 31,
2024 2023 2022
Houston Electric CERC Houston Electric CERC Houston Electric CERC (1)
(in millions)
Interest income (expense), net (2) $ 9 $ 2 $ 2 $ 10 $ - $ (18)
(1)Includes affiliate-related net interest expense of Indiana Gas and CEOH to reflect the Restructuring.
(2)Interest income is included in Other, net and interest expense is included in Interest expense and other finance charges on Houston Electric’s and CERC’s respective Statements of Consolidated Income.
CenterPoint Energy provides some corporate services to Houston Electric and CERC. The costs of services have been charged directly to Houston Electric and CERC using methods that management believes are reasonable. These methods include usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. Houston Electric provides certain services to CERC. These services are billed at actual cost, either directly or as an allocation and include fleet services, shop services, geographic services, surveying and right-of-way services, radio communications, data circuit management and field operations. Additionally, CERC provides certain services to Houston Electric. These services are billed at actual cost, either directly or as an allocation and include line locating and other miscellaneous services. These charges are not necessarily indicative of what would have been incurred had Houston Electric and CERC not been affiliates.
The table below presents amounts charged for these services, which are included primarily in Operation and maintenance expenses on Houston Electric’s and CERC’s respective Statements of Consolidated Income, for the periods presented:
Year Ended December 31,
2024 2023 2022
Houston Electric CERC Houston Electric CERC Houston Electric CERC
(in millions)
Corporate service charges $ 173 $ 213 $ 173 $ 236 $ 167 $ 237
Net affiliate service charges (billings) (5) 5 (10) 10 15 (15)
The table below presents transactions among Houston Electric, CERC and their parent, Utility Holding, for the periods presented:
Year Ended December 31,
2024 2023 2022
Houston Electric CERC Houston Electric CERC Houston Electric CERC
(in millions)
Cash dividends paid to parent $ 339 $ 442 $ 367 $ 496 $ 316 $ 124
Cash dividend paid to parent related to the sale of the Arkansas and Oklahoma Natural Gas businesses - - - - - 720
Cash contribution from parent 844 290 885 500 1,143 289
Net assets acquired in the Restructuring (1) - - - - - 2,345
Non-cash capital contribution from parent in payment for property, plant and equipment below - - - - 38 54
Cash paid to parent for property, plant and equipment below - - - - 65 61
Property, plant and equipment from parent (2) - - - - 103 115
(1)The Restructuring was a common control transaction that required the recasting of financial information to the earliest period presented. Therefore, the net asset transfer was not reflected during the year ended December 31, 2022 on CERC’s Statements of Consolidated Changes in Equity.
(2)Property, plant and equipment purchased from CenterPoint Energy at its net carrying value on the date of purchase.
(19) Leases
In 2021, Houston Electric entered into a temporary short-term lease and long-term leases for temporary generation. The short-term lease agreement expired on December 31, 2022. Effective January 1, 2023, all temporary generation assets were leased under the long-term lease agreement. Expenses associated with the short-term lease, including carrying costs, are deferred to a regulatory asset and totaled $89 million and $100 million as of December 31, 2024 and 2023, respectively.
The long-term lease agreement includes up to 505 MW of TEEEF, all of which was delivered as of December 31, 2022, triggering lease commencement at delivery, with an initial term ending in 2029 for all TEEEF leases. The total cash payments under the long-term lease totaled $664 million, with the final $485 million paid in 2022. Houston Electric derecognized the finance lease liability when the extinguishment criteria in Topic 405 - Liabilities was achieved. Per the terms of the agreement, lease payments are due and made in full by Houston Electric upon taking possession of the asset, relieving substantially all of the associated finance lease liability at that time. The remaining finance lease liability associated with the commenced long-term TEEEF agreement was not significant as of December 31, 2024 and 2023 and relates to removal costs that will be incurred at the end of the lease term. As of December 31, 2024, Houston Electric had secured a first lien on the assets leased under the prepayment agreement, except for assets with lease payments totaling $79 million, which is being held in an escrow account, not controlled by Houston Electric, and the funds will be released when a first lien can be secured by Houston Electric. Expenses associated with the long-term lease, including variable costs associated with the operation and maintenance of the temporary generation assets, depreciation expense on the right of use asset and carrying costs, are deferred to a regulatory asset as a recoverable cost under the 2021 Texas legislation and totaled $158 million and $124 million as of December 31, 2024 and 2023, respectively. For further discussion of the regulatory impacts, see Note 7.
The components of lease cost, included in Operation and maintenance expense on the Registrants’ respective Statements of Consolidated Income, are as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC
(in millions)
Operating lease cost $ 6 $ 3 $ 2 $ 6 $ 3 $ 2 $ 6 $ 1 $ 2
Short-term lease cost 12 11 - 31 30 - 167 166 1
Total lease cost (1)
$ 18 $ 14 $ 2 $ 37 $ 33 $ 2 $ 173 $ 167 $ 3
(1) CenterPoint Energy and Houston Electric defer finance lease costs for TEEEF to Regulatory assets for recovery rather than to Depreciation and Amortization in the Statements of Consolidated Income.
The components of lease income were as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC
(in millions)
Operating lease income $ 7 $ - $ 5 $ 6 $ 1 $ 4 $ 5 $ 1 $ 3
Variable lease income 1 - - 2 - - 2 - -
Total lease income $ 8 $ - $ 5 $ 8 $ 1 $ 4 $ 7 $ 1 $ 3
Supplemental balance sheet information related to leases was as follows for the periods presented:
December 31, 2024 December 31, 2023
CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC
(in millions)
Assets:
Operating ROU assets (1) $ 27 $ 5 $ 15 $ 13 $ 6 $ 4
Finance ROU assets (2) 430 430 - 526 526 -
Total leased assets $ 457 $ 435 $ 15 $ 539 $ 532 $ 4
Liabilities:
Current operating lease liability (3) $ 3 $ 1 $ 1 $ 3 $ 1 $ 1
Non-current operating lease liability (4) 25 3 14 10 5 3
Total leased liabilities (5) $ 28 $ 4 $ 15 $ 13 $ 6 $ 4
(1)Included in Other assets in the Registrants’ respective Consolidated Balance Sheets, net of accumulated amortization.
(2)Included in Property, Plant and Equipment in the Registrants’ respective Consolidated Balance Sheets, net of accumulated amortization.
(3)Included in Current other liabilities in the Registrants’ respective Consolidated Balance Sheets.
(4)Included in Other non-current liabilities in the Registrants’ respective Consolidated Balance Sheets.
(5)Finance lease liabilities were not material as of December 31, 2024 or 2023.
As of December 31, 2024 and 2023, the weighted-average remaining lease term and weighted-average discount rate for the Registrants’ finance and operating leases were as follows:
December 31, 2024 December 31, 2023
CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC
Weighted-average remaining lease term (in years) - operating leases 17.7 2.9 20.6 4.7 3.9 3.1
Weighted-average discount rate - operating leases 4.92 % 4.11 % 5.03 % 4.13 % 4.09 % 3.60 %
Weighted-average remaining lease term (in years) - finance leases 4.5 4.5 - 5.5 5.5 -
Weighted-average discount rate - finance leases 3.60 % 3.60 % - 3.60 % 3.60 % -
As of December 31, 2024, finance lease liabilities were not significant to the Registrants. As of December 31, 2024, maturities of operating lease liabilities were as follows:
CenterPoint
Energy Houston
Electric CERC
(in millions)
2025 $ 4 $ 2 $ 2
2026 4 1 2
2027 3 1 1
2028 2 - 1
2029 2 - 1
Thereafter 30 - 19
Total lease payments 45 4 26
Less: Interest 17 - 11
Present value of lease liabilities $ 28 $ 4 $ 15
As of December 31, 2024, future minimum finance lease payments to be received were not significant to the Registrants. As of December 31, 2024, maturities of undiscounted operating lease payments to be received were as follows:
CenterPoint
Energy Houston
Electric CERC
(in millions)
2025 $ 9 $ 1 $ 6
2026 9 - 6
2027 8 - 7
2028 4 - 2
2029 1 - -
Thereafter 1 - -
Total lease payments to be received $ 32 $ 1 $ 21
Other information related to leases is as follows for the periods presented:
Year Ended December 31,
2024 2023 2022
CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC CenterPoint Energy Houston
Electric CERC
(in millions)
Operating cash flows from operating leases included in the measurement of lease liabilities $ 5 $ 2 $ 2 $ 5 $ 2 $ 2 $ 6 $ 1 $ 2
Financing cash flows from finance leases included in the measurement of lease liabilities - - - - - - 485 485 -
See Note 17 for information on ROU assets obtained in exchange for operating lease liabilities.
(20) Subsequent Events
Credit Facilities
On January 29, 2025, CenterPoint Energy, Houston Electric, CERC and SIGECO each entered into Extension Agreements to, among other things, extend the maturity date of the lenders’ commitments under each of their respective Credit Agreements by one year, from December 6, 2027 to December 6, 2028.
SIGECO First Mortgage Bonds (CenterPoint Energy)
On January 31, 2025, SIGECO issued $165 million aggregate principal amount of 5.69% First Mortgage Bonds, Series 2025A, Tranche A due 2055. Total net proceeds from SIGECO’s January 2025 issuance of first mortgage bonds, net of transaction expenses and fees, were approximately $164 million, which will be used for the acquisition of Posey Solar.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A.Controls and Procedures
Disclosure Controls And Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, the Registrants carried out separate evaluations, under the supervision and with the participation of each company’s management, including the principal executive officer and principal financial officer, of the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report. Based on those evaluations, the principal executive officer and principal financial officer, in each case, concluded that the disclosure controls and procedures were effective as of December 31, 2024 to provide assurance that information required to be disclosed in the reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.
Changes in Internal Control Over Financial Reporting
There has been no change in the Registrants’ internal controls over financial reporting that occurred during the three months ended December 31, 2024 that has materially affected, or is reasonably likely to materially affect, the Registrants’ internal controls over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
The Registrants’ management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Registrants’ principal executive and principal financial officers and effected by CenterPoint Energy’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
•Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Registrants;
•Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Registrants are being made only in accordance with authorizations of management and directors of the Registrants; and
•Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Registrants’ assets that could have a material effect on the financial statements.
Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America. Management’s assessment included review and testing of both the design effectiveness and operating effectiveness of controls over all relevant assertions related to all significant accounts and disclosures in the financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of the Registrants’ management, including their respective principal executive officers and principal financial officers, the Registrants conducted an evaluation of the effectiveness of their internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Registrants’ evaluation under the framework in Internal Control - Integrated Framework (2013), the Registrants’ management has concluded, in each case, that their internal control over financial reporting was effective as of December 31, 2024.
Deloitte & Touche LLP, CenterPoint Energy’s independent registered public accounting firm, has issued an attestation report on the effectiveness of CenterPoint Energy’s internal control over financial reporting as of December 31, 2024 which is set forth below. This report is not applicable to Houston Electric or CERC as they are not accelerated or large accelerated filers.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
CenterPoint Energy, Inc.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2024, of the Company and our report dated February 20, 2025, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 20, 2025

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ITEM 9B. OTHER INFORMATION
Item 9B.Other Information
None.
Rule 10b5-1 Trading Arrangements
During the three months ended December 31, 2024, no director or officer of CenterPoint Energy, Houston Electric or CERC adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10.Directors, Executive Officers and Corporate Governance
For CenterPoint Energy, the information called for by Item 10, to the extent not set forth in “Information About Our Executive Officers” in Item 1 of Part I of this report, will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2025 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 10 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
For Houston Electric and CERC, the information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

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ITEM 11. EXECUTIVE COMPENSATION
Item 11.Executive Compensation
For CenterPoint Energy, the information called for by Item 11 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2025 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 11 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
For Houston Electric and CERC, the information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
For CenterPoint Energy, the information called for by Item 12 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2025 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 12 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
For Houston Electric and CERC, the information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13.Certain Relationships and Related Transactions, and Director Independence
For CenterPoint Energy, the information called for by Item 13 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2025 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 13 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
For Houston Electric and CERC, the information called for by Item 13 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly-Owned Subsidiaries).

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14.Principal Accounting Fees and Services
For CenterPoint Energy, the information called for by Item 14 will be set forth in the definitive proxy statement relating to CenterPoint Energy’s 2025 annual meeting of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a meeting of shareholders involving the election of directors and the portions thereof called for by Item 14 are incorporated herein by reference pursuant to Instruction G to Form 10-K.
Aggregate fees billed to Houston Electric and CERC during the years ended December 31, 2024 and 2023 by their principal accounting firm, Deloitte & Touche LLP, are set forth below.
Year Ended December 31,
2024 2023
Houston Electric CERC Houston Electric CERC
Audit fees (1)
$ 948,480 $ 1,337,600 $ 843,661 $ 1,155,700
Audit-related fees (2)
1,088,145 449,000 530,000 410,000
Total audit and audit-related fees 2,036,625 1,786,600 1,373,661 1,565,700
Tax fees - - - -
All other fees - - - -
Total fees $ 2,036,625 $ 1,786,600 $ 1,373,661 $ 1,565,700
(1)For 2024 and 2023, amounts include fees for services provided by the principal accounting firm relating to the integrated audit of financial statements and internal control over financial reporting, statutory audits, attest services, and regulatory filings.
(2)For 2024 and 2023, amounts include fees for consultations concerning financial accounting and reporting standards and various agreed-upon or expanded procedures related to accounting records to comply with financial accounting or regulatory reporting matters.
Houston Electric and CERC each are not required to have, and do not have, an audit committee.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15.Exhibits and Financial Statement Schedules
(a)(1) Financial Statements.
CenterPoint Energy
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
Statements of Consolidated Income for the Three Years Ended December 31, 2024
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2024
Consolidated Balance Sheets as of December 31, 2024 and 2023
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2024
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2024
Houston Electric
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
Statements of Consolidated Income for the Three Years Ended December 31, 2024
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2024
Consolidated Balance Sheets as of December 31, 2024 and 2023
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2024
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2024
CERC
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)
Statements of Consolidated Income for the Three Years Ended December 31, 2024
Statements of Consolidated Comprehensive Income for the Three Years Ended December 31, 2024
Consolidated Balance Sheets as of December 31, 2024 and 2023
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2024
Statements of Consolidated Changes in Equity for the Three Years Ended December 31, 2024
Combined Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2024
The following schedules are omitted by the Registrants because of the absence of the conditions under which they are required or because the required information is included in the financial statements:
I, II, III, IV and V.
(a)(3) Exhibits.
See Index of Exhibits beginning on page 187, which index also includes the management contracts or compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.