CNP

CENTERPOINT ENERGY INC

NYSE · UTILITIES · ELECTRIC SERVICES

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MKT CAP $26.4BP/E 24.7DIV YIELD 2.21%FCF YIELD -10.13%REV TTM $9.4B +5.2%NET INCOME $1.1B +10.9%NET DEBT $19.9B52W 36.62 – 45.04SEC XBRL · TTM TO Invalid Date

How CNP rewrote its risk factors

10-K ITEM 1A · FY2024 → FY2025

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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 Transmission, Distribution and Generation (CenterPoint Energy and Houston Electric) Disruptions at third-party or Indiana Electric’s power generation facilities, generation inadequacy, directives issued by regulatory authorities or other matters could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and Houston Electric and Indiana Electric may not be able to promptly respond, repair and restart their facilities, which could adversely affect their businesses, 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 bulk power generation facilities.
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 independent system operator, ERCOT and MISO, respectively.
ERCOT and MISO have in the past and may in the future issue directives requiring members to implement controlled outages as a result of an emergency or reliability issues.
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 Load Shed and which customers experienced outages and the duration of those outages.
As a result, claims and lawsuits could be filed against CenterPoint Energy for personal injury, property damage or other damage or loss as a result of its Load Shed planning, preparation, implementation, and decisions in order to meet the directives of ERCOT and MISO, respectively.
For example, during the February 2021 Winter Storm Event, the ERCOT regulated Texas electric system experienced an unprecedented power generation shortage as 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.
CenterPoint Energy received various claims and lawsuits with respect to the February 2021 Winter Storm Event, alleging, among other things, wrongful death, personal injury, property damage and other injuries and damages.
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 or in the event of significant system disturbances, Houston Electric’s or Indiana Electric’s transmission and distribution services may be diminished, interrupted or halted, which could lead to prolonged customer outages, and Houston Electric and Indiana Electric may not be able to promptly repair and restart their facilities, which could adversely affect our businesses, financial condition, results of operations and cash flows.
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, which could also adversely affect our business, financial condition, and results of operations.
Additionally, Indiana Electric’s generating facilities are subject to operational risks, and Houston Electric and Indiana Electric are subject to risk relating to the generating facilities that supply the power transmitted by Houston Electric and Indiana Electric; these risks have in the past and may in the future result in service interruptions and unscheduled outages, unanticipated operation and maintenance expenses, reputational harm and increased purchase power costs.
Culley Unit 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 business, financial condition, results of operations and cash flows.
Further, Indiana Electric is party to a number of PPAs with third parties.
Indiana Electric’s operations may be disrupted or otherwise insufficient if third parties do not deliver required power under our PPAs.
These risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator or other human 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 production or delivery of electricity; inability to comply with regulatory or permit requirements; governmental action; labor disputes; severe weather; natural disasters; or cyberattacks, all of which could adversely affect Indiana Electric’s and Houston Electric’s businesses, including their financial condition, results of operations and cash flows.
Further, Indiana Electric currently relies on coal for a portion of its generation capacity.
Indiana Electric purchases the majority of its coal supply, and in 2025 purchased all 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 business, financial condition, results of operations and cash flows.
Future labor shortages in the coal industry as well as coal supply shortages (such as those experienced by Indiana Electric in 2021 and part of 2022), may lead to increased cost and have an adverse impact on our business, financial condition, results of operations and cash flows.
Further, as Indiana Electric’s generating facilities may experience unanticipated disruptions as a result of renewable supply shortages, including, but not limited to, unfavorable wind and solar conditions such as cloudy or windless days, and such disruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s business, financial condition, results of operations and cash flows.
The operations of Houston Electric and Indiana Electric are subject to the usual hazards associated with 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, loss or outage of key technology platforms or systems, 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 environmental damage, and may result in suspension of operations, disruption of service to customers, prolonged outages and the imposition of civil or criminal penalties.
For example, in 2024, Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in a substantial number of its customers being without power, many for extended periods of time.
Although CenterPoint Energy currently maintains property and casualty insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover the costs associated with potential hazards incident to Houston Electric and Indiana Electric’s businesses, and there is no guarantee that the insurance that CenterPoint Energy currently maintains will continue to be available at rates we believe are reasonable.
Indiana Electric’s execution of its generation transition plan 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 develop 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, cost effective 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, including the 2025 IRP, have identified preferred portfolios that include a wider mix of generating resources such as coal-fired generation, solar, wind, solar with storage and dispatchable natural gas combustion turbines.

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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.
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).
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.
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.
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.

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Sentence-level comparison of Item 1A in the two most recent 10-Ks (FY2024 ↗, FY2025 ↗). A reworded sentence counts as one dropped and one added, so heavy edits read as low “kept”. Headings and page furniture are stripped; nothing is summarised by a model.

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