CENTERPOINT ENERGY INC

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Debt Transactions. During the three months ended March 31, 2024, CenterPoint Energy issued or borrowed a combined $400 million in new debt, comprised of Houston Electric’s issuance of $400 million aggregate principal amount of 5.15% general mortgage bonds due 2034. During the three months ended March 31, 2024, CenterPoint Energy repaid or redeemed a combined $22 million of existing debt, including SIGECO’s redemption of $22 million aggregate principal amount of outstanding first mortgage bonds due 2024. For information about debt transactions to date in 2024, see Note 11 to the Interim Condensed Financial Statements.

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Debt Transactions. For information about debt transactions to date in 2024, see Note 11 to the Interim Condensed Financial Statements.

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Income available to common shareholders for the three months ended March 31, 2024 and 2023 was as follows:

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Income available to common shareholders for the three and six months ended June 30, 2024 and 2023 was as follows:

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Income available to common shareholders increased $37 million primarily due to the following items:

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Income available to common shareholders increased $122 million primarily due to the following items:

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•a decrease in income available to common shareholders of $2 million for the Electric reportable segment, as further discussed below;

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•an increase in income available to common shareholders of $35 million for the Electric reportable segment, as further discussed below;

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•a decrease in income available to common shareholders of $10 million for Corporate and Other, primarily due to $18 million increase in borrowing costs, partially offset by $12 million of dividends paid on shares of Series A Preferred Stock paid in the first quarter of 2023 prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023 as discussed in Note 18 to the Interim Condensed Financial statements.

Current wording

•an increase in income available to common shareholders of $75 million for Corporate and Other, primarily due to $12 million of income allocated to holders of Series A Preferred Stock in the second quarter of 2023 prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023 as discussed in Note 18 to the Interim Condensed Financial statements, a loss on sale of $12 million and current tax expense of $33 million related to divestiture of Energy Systems Group recorded during the three months ended June 30, 2023 further discussed in Note 3 to the Interim Condensed Financial Statements, as well as $19 million due to remeasurement of deferred income tax balances recorded during the three months ended June 30, 2023. The increase is partially offset by $12 million increase in borrowing costs.

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The following table provides variance explanations for the three months ended March 31, 2024 compared to the three months ended March 31, 2023 by major income statement caption for CenterPoint Energy’s Electric reportable segment:

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The following table provides variance explanations for the three months ended June 30, 2024 compared to the three months ended June 30, 2023 as well as for the six months ended June 30, 2024 compared to the six months ended June 30, 2023 by major income statement caption for CenterPoint Energy’s Electric reportable segment:

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The following table provides variance explanations for the three months ended March 31, 2024 compared to the three months ended March 31, 2023 by major income statement caption for CenterPoint Energy’s Natural Gas reportable segment:

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The following table provides variance explanations for the three months ended June 30, 2024 compared to the three months ended June 30, 2023 as well as for the six months ended June 30, 2024 compared to the six months ended June 30, 2023 by major income statement caption for CenterPoint Energy’s Natural Gas reportable segment:

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The following table provides variance explanations for the three months ended March 31, 2024 compared to the three months ended March 31, 2023 by major income statement caption for Houston Electric:

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The following table provides variance explanations for the three months ended June 30, 2024 compared to the three months ended June 30, 2023 as well as for the six months ended June 30, 2024 compared to the six months ended June 30, 2023 by major income statement caption for Houston Electric:

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The following table provides variance explanations for the three months ended March 31, 2024 compared to the three months ended March 31, 2023 by major income statement caption for CERC:

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The following table provides variance explanations for the three months ended June 30, 2024 compared to the three months ended June 30, 2023 as well as for the six months ended June 30, 2024 compared to the six months ended June 30, 2023 by major income statement caption for CERC:

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For information on other developments, factors and trends that may have an impact on the Registrants’ future earnings, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I of the Registrants’ combined 2023 Form 10-K, and “Cautionary Statement Regarding Forward-Looking Information” in this combined Form 10-Q.

Current wording

For information on other developments, factors and trends that may have an impact on the Registrants’ future earnings, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I of the Registrants’ combined 2023 Form 10-K, and “Cautionary Statement Regarding Forward-Looking Information” and “Risk Factors” in this combined Form 10-Q.

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The following table summarizes the net cash provided by (used in) operating, investing and financing activities during the three months ended March 31, 2024 and 2023:

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The following table summarizes the net cash provided by (used in) operating, investing and financing activities during the six months ended June 30, 2024 and 2023:

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Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the three months ended March 31, 2024 compared to the three months ended March 31, 2023:

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Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the six months ended June 30, 2024 compared to the six months ended June 30, 2023:

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Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities for the three months ended March 31, 2024 compared to the three months ended March 31, 2023:

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Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities for the six months ended June 30, 2024 compared to the six months ended June 30, 2023:

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Financing Activities. The following items contributed to (increased) decreased net cash used in financing activities for the three months ended March 31, 2024 compared to the three months ended March 31, 2023:

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Financing Activities. The following items contributed to (increased) decreased net cash used in financing activities for the six months ended June 30, 2024 compared to the six months ended June 30, 2023:

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The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures are expected to be used for investment in infrastructure. These capital expenditures are anticipated to maintain reliability and safety, increase resiliency and expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for the remaining nine months of 2024 include the following:

Current wording

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 the May 2024 Storm Events and 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 the remaining six months of 2024 include the following:

Previous wording

The Registrants expect that anticipated cash needs for the remaining nine months of 2024 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, proceeds from equity issuances, anticipated cash flows from operations, and, with respect to CenterPoint Energy and CERC, proceeds from commercial paper. Proceeds from equity issuances may include the issuance of shares of Common Stock under the Equity Distribution Agreement entered into on January 10, 2024. Issuances of debt securities in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available on acceptable terms.

Current wording

The Registrants expect that anticipated cash needs for the remaining six months of 2024 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, proceeds from equity issuances, anticipated cash flows from operations, and, with respect to CenterPoint Energy and CERC, proceeds from commercial paper. Proceeds from equity issuances may include the issuance of shares of Common Stock under the Equity Distribution Agreement entered into on January 10, 2024. 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.

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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 have 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 February 27, 2024, Indiana Electric provided notice that it was exercising its right to terminate the BTA, which terminated all further obligations of Indiana Electric with respect to the project.

Current wording

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 February 27, 2024, Indiana Electric provided notice that it was exercising its right to terminate the BTA, which terminated all further obligations of Indiana Electric with respect to the project.

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Indiana Electric also sought approval in February 2021 for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which provides equivalent equity return to offset imputed debt during the 25 year life of the PPA. In October 2021, the IURC approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising project costs caused by inflation and supply chain issues affecting the energy industry, Clenera LLC and Indiana Electric were compelled to renegotiate terms of the agreement to increase the PPA price. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with certain modifications. Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date could be delayed from 2025 to 2026.

Current wording

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.

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County, Indiana had increased. The increase was largely driven by escalating commodity and supply chain costs impacting manufacturers worldwide. In August 2022, Indiana Electric and Origis entered into an amended PPA, which reiterated the terms contained in the 2021 PPA with certain modifications. On February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date will be delayed from 2024 to 2025. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with Oriden with certain modifications. Revised purchase power costs were approved to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden. On May 30, 2023, the IURC approved the Vermillion County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date could be delayed from 2025 to 2026.

Current wording

On August 25, 2021, Indiana Electric filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden, which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis, which is developing a solar project in Knox County, Indiana. On May 4, 2022, the IURC issued an order approving Indiana Electric to enter into both PPAs. In March 2022, when the results of the MISO interconnection study were completed, Origis advised Indiana Electric that the costs to construct the solar project in Knox County, Indiana had increased. The increase was largely driven by escalating commodity and supply chain costs impacting manufacturers worldwide. In August 2022, Indiana Electric and Origis entered into an amended PPA, which reiterated the terms contained in the 2021 PPA with certain modifications. On February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date will be delayed from 2024 to 2026. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with Oriden with certain modifications. 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.

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In June 2022, F.B. Culley Unit 3, an Indiana Electric coal-fired electric generation unit with an installed generating capacity of 270 MW, experienced an operating issue relating to its boiler feed pump turbine. The unit returned to service in March 2023. In testimony filed September 13, 2023, the OUCC and an intervenor that represents industrial customers filed testimony with the IURC alleging that Indiana Electric did not act prudently which led to the unplanned outage and recommended disallowances between $21 million to $27 million. On October 23, 2023, Indiana Electric filed rebuttal testimony with the IURC and an evidentiary hearing was held on November 2, 2023. Indiana Electric expects a decision from the IURC later this year.

Current wording

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 subject to appeal for a 30-day period.

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On December 17, 2020, Houston Electric filed a CPCN with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first half of 2025.

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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 2025.

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On November 17, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Harris and Montgomery counties, Texas that will connect Houston Electric’s transmission system to Houston Electric’s planned Mill Creek substation. The actual capital costs of the project, including the transmission line and the planned Kilgore substation, will depend on actual land acquisition costs, construction costs, and other factors and have been estimated to be $62 million to $98 million, based on an amended CCN application filed by Houston Electric on February 26, 2024. A decision on the approval of the project in the PUCT proceeding is expected in the third quarter of 2024.

Current wording

On November 17, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Harris and Montgomery counties, Texas that will connect Houston Electric’s transmission system to Houston Electric’s planned Mill Creek substation. The actual capital costs of the project, including the transmission line and the planned Mill Creek substation, will depend on actual land acquisition costs, construction costs, and other factors and have been estimated to be $62 million to $98 million, based on an amended CCN application filed by Houston Electric on February 26, 2024 and subsequent errata filed on May 9, 2024. A decision by the PUCT on the approval of the project is expected in the second half of 2024.

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•House Bill 2555 became effective on June 13, 2023 and allows an electric utility to create a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, undergrounding certain lines, flood mitigation measures, and vegetation management. On January 18, 2024, the PUCT issued an Order adopting its Resiliency Plan Rule (16 TAC 25.62);

Current wording

•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 Texas Admin Code § 25.62);

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

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

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On June 28, 2023, CERC submitted its first innovation plan to the MPUC; the five-year plan includes 18 pilot projects and seven smaller research-and-development projects. These projects will deploy and evaluate a broad array of innovative resources including made-in-Minnesota alternative gases such as renewable natural gas and green hydrogen as well as pioneering technologies such as a networked geothermal district energy system and end-use carbon capture. The proposed plan requires approval from the MPUC through a review process that is expected to take about one year. The MPUC requested comments by September 15, 2023 if parties believe that the filing is incomplete based on the reporting requirements or if parties do not believe that that the MPUC’s standard informal proceeding process is appropriate. No parties filed comments regarding completeness or raising concerns that the MPUC’s standard informal procedural process is inappropriate. The initial comment period closed January 15, 2024, the reply comment period closed March 15, 2024 and supplemental comments are due May 15, 2024; CERC anticipates the MPUC will hear this matter after the final comments are received.

Current wording

On June 28, 2023, CERC submitted its first innovation plan to the MPUC; the five-year plan includes 18 pilot projects and seven smaller research-and-development projects. These projects will deploy and evaluate a broad array of innovative resources including made-in-Minnesota alternative gases such as renewable natural gas and green hydrogen as well as pioneering technologies such as a networked geothermal district energy system and end-use carbon capture. The proposed plan requires approval from the MPUC through a review process that is expected to take about one year. The MPUC requested comments by September 15, 2023 if parties believe that the filing is incomplete based on the reporting requirements or if parties do not believe that that the MPUC’s standard informal proceeding process is appropriate. No parties filed comments regarding completeness or raising concerns that the MPUC’s standard informal procedural process is inappropriate. The initial comment period closed January 15, 2024, the reply comment period closed March 15, 2024 and the supplemental comments period closed 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 is anticipated to be issued in the third quarter of 2024.

Previous wording

CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs. The potential delays and inflationary cost pressures communicated from the developers of our solar projects have been primarily due to (i) unavailability of solar panels and other uncertainties related to a DOC investigation on anti-dumping and countervailing duties petition filed by a domestic solar manufacturer, (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On December 2, 2022, the DOC issued its preliminary determination, finding four of the eight companies being investigated are attempting to bypass U.S. duties. On August 18, 2023, the DOC announced its final determination and found that five of the eight companies investigated are attempting to bypass U.S. duties by doing minor processing in one of the Southeast Asian countries before shipment to the United States. Pursuant to President Biden’s executive order issued in June 2022, duties will not be collected on any solar module and cell imports from these Southeast Asian countries until June 2024, as long as the imports are consumed in the U.S. market within six months of the termination of the executive order. The executive order could be subject to legal and legislative challenges and its effects remain uncertain. The resolution of these issues will determine what additional costs or delays our solar projects will be subject to. These impacts have resulted in cost increases for certain projects, and may result in cost increases in other projects, and such impacts have resulted in, or are expected to result in, the need for us to seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects. For more information regarding potential delays, cancellations and supply chain disruptions, see “Item 1A. Risk Factors” in the Registrants’ combined 2023 Form 10-K.

Current wording

CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs. The potential delays and inflationary cost pressures communicated from the developers of our solar projects have been primarily due to (i) unavailability of solar panels and other uncertainties related to a DOC investigation on anti-dumping and countervailing duties petition filed by American Alliance of Solar Manufacturing Trade Committee, (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, the DOC announced the initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells, from Cambodia, Malaysia, Thailand, and Vietnam. The DOC is expected to issue a preliminary countervailing duty ruling in September 2024 and a preliminary antidumping ruling in the fourth quarter of 2024. On June 7, 2024, the U.S. International Trade Commission preliminarily determined that U.S. solar manufactures are being harmed by unfair trade practices from competitors in Southeast Asia. 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 “Item 1A. Risk Factors” in the Registrants’ combined 2023 Form 10-K.

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House Bill 2555 was passed by the 88th Texas Legislature in 2023 and allows an electric utility to create a transmission and distribution system resiliency plan to enhance its system through the implementation of 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.

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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.

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On April 29, 2024, Houston Electric filed its first transmission and distribution system resiliency plan with the PUCT for review and approval. Houston Electric’s transmission and distribution system resiliency plan proposes to enhance its system over a three year period through twenty-five (25) measures related to: system hardening, grid modernization, flood mitigation, information technology, physical security, and vegetation management. Houston Electric’s transmission and distribution system resiliency plan also proposes to further analyze and identify specific wildfire risk and implement additional measures to mitigate the identified wildfire risk. The estimated capital cost is approximately $2.2 billion, the estimated incremental operations and maintenance expense is approximately $86 million over the three year period, and Houston Electric has requested that the PUCT allow Houston Electric to establish a regulatory asset for distribution related costs. The PUCT has 180 days to make a decision on Houston Electric’s transmission and distribution system resiliency plan, and a final decision is expected in the fourth quarter of 2024.

Current wording

On April 29, 2024, Houston Electric filed its first transmission and distribution system resiliency plan with the PUCT for review and approval. Houston Electric’s transmission and distribution system resiliency plan proposes to implement twenty-five (25) resiliency measures over a three-year period related to: system hardening, grid modernization, flood mitigation, information technology, physical security, and vegetation management. Houston Electric’s transmission and distribution system resiliency plan proposes to further analyze and identify specific wildfire risk and implement additional measures to mitigate the identified wildfire risk. Additionally, Houston Electric is proposing two pilot programs and one activity: 1) a utility-scale microgrid pilot program, 2) a pilot program to fund a City of Houston department responsible for overseeing resiliency issues for the City of Houston, and 3) the transition and migration of Houston Electric’s Systems, Applications & Products in Data Processing software to a cloud-based application. The estimated capital cost is approximately $2.2 billion, and the estimated incremental operations and maintenance expense is approximately $86 million over the three year period. Houston Electric has requested that the PUCT allow Houston Electric to establish a regulatory asset for distribution-related costs relating to the implementation of Houston Electric’s transmission and distribution system resiliency plan. Intervenors and staff filed direct testimony on June 24, 2024 and July 2, 2024, respectively; Houston Electric filed rebuttal testimony on July 15, 2024. On July 19, 2024, parties filed a joint motion to abate the proceedings, which was amended on July 22, 2024. The State Office of Administrative Hearings ALJ approved the joint motion on July 22, 2024. The parties will provide an update on the status of settlement negotiations by October 22, 2024 and every month thereafter.

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Texas Gas Rate Case. On October 30, 2023 CERC filed an application with the Railroad Commission and municipal regulatory authorities to set new natural gas base rates that would be applied consistently across the approximately 1.9 million customers. The requested increase is approximately 3.1% or $37 million based on an historical test year ending June 30, 2023. The need for a rate change is primarily driven by the continuing investment in the safety and reliability of the natural gas system, including new Intelis natural gas meters that feature an integrated safety shutoff valve, changes to depreciation rates that better reflect the actual life and salvage characteristics of assets, and changes in other costs to serve customers. The request reflects a proposed 10.50% ROE on a 60.61% equity ratio. Intervenor testimony was filed March 8, 2024, rebuttal testimony addressing intervenor issues was filed March 29, 2024 and a settlement agreement was filed on April 23, 2024. A hearing was held on April 24, 2024. A final order is expected in the second quarter of 2024.

Current wording

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, establishes a 9.80% ROE and a 60.61% equity ratio for future GRIP filings. New rates will be effective beginning the month of December 2024.

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Indiana Electric Rate Case. On December 5, 2023, Indiana Electric filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase is approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase is primarily driven by the continuing investment that is being made to bolster the safety and reliability of the system and normal increases in operating expenses. The rate case reflects a proposed 10.4% ROE on a 55% equity ratio. On April 9, 2024 Indiana Electric filed rebuttal in the rate case. The requested increase remains at 16% with an updated requested increase of $115 million. A hearing is scheduled to begin May 2, 2024. A final order is expected in the fourth quarter of 2024.

Current wording

Indiana Electric Rate Case. On December 5, 2023, Indiana Electric filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase is approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase is primarily driven by the continuing investment that is being made to bolster 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 55% equity ratio. On April 9, 2024 Indiana Electric filed rebuttal in the rate case. 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 55% equity ratio. The requested increase was lowered to 11% with an updated requested increase of $80 million. A hearing is scheduled to begin September 3, 2024. A final order is expected in the first quarter of 2025.

Previous wording

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. Texas law mandates that electric utilities file a base rate proceeding no later than every four years from the date of their last base rate proceeding final order. Houston Electric’s most recent base rate proceeding order was approved by the PUCT on March 9, 2020, in Docket No. 49421. Therefore, Houston Electric was required to file a next base rate proceeding no later than March 9, 2024. 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. Intervenor and PUCT Staff testimony is expected in June 2024, followed by rebuttal on July 12, 2024. A hearing on the merits is scheduled to start in late July 2024 and a final order is expected late fourth quarter of 2024 or the first quarter of 2025.

Current wording

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. Texas law mandates that electric utilities file a base rate proceeding no later than every four years from the date of their last base rate proceeding final order. Houston Electric’s most recent base rate proceeding order was approved by the PUCT on March 9, 2020, in Docket No. 49421. Therefore, Houston Electric was required to file its next base rate proceeding no later than March 9, 2024. 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. Intervenor and PUCT staff testimony was filed in June 2024. Rebuttal testimony was due on July 12, 2024 and Houston Electric filed rebuttal testimony from 13 witnesses that covered issues other than operations; however, due to their significant operational responsibilities associated with Houston Electric’s emergency operations plan and response to Hurricane Beryl, an extension was requested (and granted) for the operations witnesses. A hearing on the merits was scheduled to start in late July 2024. On July 17, 2024, Houston Electric filed an unopposed motion to abate the pending deadlines in order to provide additional time to facilitate the continued settlement discussions; the motion was granted on the same day. Houston Electric will provide the ALJs an update on the status of settlement negotiations by August 2, 2024 and every two weeks thereafter.

Previous wording

On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. On May 11, 2023, the EPA announced proposed emission limits and guidelines for carbon dioxide from fossil fuel-fired power plants under Section 111 of the Clean Air Act which, if finalized, apply new GHG performance standards for those existing coal-fired units expected to continue operation beyond December 31, 2029. On February 29, 2024, EPA announced that it would be delaying the rulemaking as applied to existing 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, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029.

Current wording

On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. On May 11, 2023, the EPA announced proposed emission limits and guidelines for carbon dioxide from fossil fuel-fired power plants under Section 111 of the Clean Air Act which, if finalized, apply new GHG performance standards for those existing coal-fired units expected to continue operation beyond December 31, 2029. On February 29, 2024, the EPA announced that it would be delaying the rulemaking as applied to existing 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

Previous wording

Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 emissions estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the U.S. Energy Information Administration (EIA) Form EIA-176 reports and do not take into account the emissions of transport customers and emissions related to upstream extraction. These emission goals are expected to be used to position CenterPoint Energy to comply with anticipated future regulatory requirements from the current and future administrations to further reduce GHG emissions. CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of reducing the consumption of natural gas. The IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, and the EPA has proposed new regulations targeting reductions in methane emissions, which if implemented will increase costs related to production, transmission and storage of natural gas.

Current wording

The Biden administration recommitted the United States to the Paris Agreement, which has driven a renewed regulatory push to require further GHG emission reductions from the energy sector, and led negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035 from a 2021 baseline, which formed the basis of the U.S. commitments announced in Glasgow. In September 2021, CenterPoint Energy announced its net zero emissions goals for both Scope 1 emissions and certain Scope 2 emissions by 2035 as well as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035. 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 the current and future administrations to further reduce GHG emissions. CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of reducing the consumption of natural gas. The IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, and the EPA has proposed new regulations targeting reductions in methane emissions, which if implemented will increase costs related to production, transmission and storage of natural gas.

Previous wording

As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Registrants’ services. As these technologies 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’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Conversely, demand for the Registrants’

Current wording

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’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Conversely, demand for the Registrants’ services may increase as a result of customer changes in response to climate change. For example, as the expected utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of CenterPoint Energy’s systems and services. Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation.

Previous wording

To the extent climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales. On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity used for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event. Since many of the Registrants’ facilities are located along or near the Texas gulf coast, increased or more severe hurricanes or tornadoes could increase costs to repair damaged facilities and restore service to customers. CenterPoint Energy’s current 10-year capital plan includes capital expenditures to maintain reliability and safety and increase resiliency of its systems as climate change may result in more frequent significant weather events. Houston Electric does not own or operate any electric generation facilities other than, since September 2021, its operation of TEEEF. Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. To the extent adverse weather conditions affect the Registrants’ suppliers, results from their energy delivery businesses may suffer. For example, in Texas, the February 2021 Winter Storm Event caused an electricity generation shortage that was severely disruptive to Houston Electric’s service territory and the wholesale generation market and also caused a reduction in available natural gas capacity. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact our ability to secure cost-efficient insurance.

Current wording

To the extent climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales. On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity used for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event, 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, such as hurricanes, tornadoes or flooding, could increase costs to repair damaged facilities and restore service to customers. CenterPoint Energy’s current 10-year capital plan includes capital expenditures to enhance 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 an estimated 2.26 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.

Previous wording

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. The final rules require Registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about the Registrants’ board of directors oversight and management’s role in managing material climate-related risks. The final rule also requires the Registrants to provide information related to any climate-related targets or goals that are material to the Registrants’ businesses, results of operations, or financial condition. A majority of the reporting requirements are applicable to the fiscal year beginning in 2025, with the addition of assurance reporting for GHG inventories starting in 2029 for large accelerated filers. Litigation challenging the new rule was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. District 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. District Court of Appeals considers the litigation. The Registrants are currently evaluating the impact of the final rules on their respective consolidated financial statements and related disclosures.

Current wording

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. The final rules require Registrants to disclose, among other things, material climate-related risks, activities to mitigate such risks and information about the Registrants’ board of directors’ oversight and management’s role in managing material climate-related risks. The final rule also requires the Registrants to provide information related to any climate-related targets or goals that are material to the Registrants’ businesses, results of operations, or financial condition. 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. The Registrants continue to evaluate the impact of the final rules on their respective consolidated financial statements and related disclosures.

Previous wording

If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought its liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on March 31, 2024, deferred taxes of approximately $764 million would have been payable in 2024. If all the ZENS-Related Securities had been sold on March 31, 2024, capital gains taxes of approximately $63 million would have been payable in 2024 based on 2024 tax rates in effect. For additional information about ZENS, see Note 10 to the Interim Condensed Financial Statements.

Current wording

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 June 30, 2024, deferred taxes of approximately $779 million would have been payable in 2024. If all the ZENS-Related Securities had been sold on June 30, 2024, capital gains taxes of approximately $67 million would have been payable in 2024 based on 2024 tax rates in effect. For additional information about ZENS, see Note 10 to the Interim Condensed Financial Statements.

Previous wording

•increases in interest expense in connection with debt refinancings and borrowings under credit facilities or term loans or the use of alternative sources of financings on capital and other financial markets;

Current wording

•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, on capital and other financial markets;

Previous wording

•slower customer payments and increased write-offs of receivables due to higher natural gas prices, changing economic conditions, public health threats or severe weather events (CenterPoint Energy and CERC);

Current wording

•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);

Previous wording

•the outcome of litigation, including litigation related to the February 2021 Winter Storm Event;

Current wording

•the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl;