CENTERPOINT ENERGY HOUSTON ELECTRIC LLC

Previous wording

Equity Distribution Agreement. In April 2025, CenterPoint Energy entered into forward sale agreements with counterparties relating to 3,277,764 shares and 680,902 shares of Common Stock at an initial forward price of $36.29 and $36.72, respectively. For additional information, see Note 15 and Note 16 to the Interim Condensed Financial Statements.

Current wording

Equity Distribution Agreement. In April 2025, CenterPoint Energy entered into separate forward sale agreements pursuant to the Equity Distribution Agreement with certain of the ATM Forward Purchasers relating to 3,277,764 shares and 680,902 shares of Common Stock at an initial forward price of $36.29 per share and $36.72 per share, respectively. In May 2025, CenterPoint Energy entered into a forward sale agreement with an ATM Forward Purchaser relating to 521,962 shares of Common Stock at an initial forward price of $37.49 per share. For additional information, see Note 15 to the Interim Condensed Financial Statements.

Previous wording

Debt Transactions. For information about debt transactions to date in 2025, see Note 9 to the Interim Condensed Financial Statements.

Current wording

Debt Transactions. For information about debt transactions to date in 2025, see Note 9 and Note 16 to the Interim Condensed Financial Statements.

Previous wording

Net income for the three months ended March 31, 2025 and 2024 was as follows:

Current wording

Net income for the three and six months ended June 30, 2025 and 2024 was as follows:

Previous wording

Net income decreased $53 million primarily due to the following items:

Current wording

Net income decreased $30 million primarily due to the following items:

Previous wording

•a decrease in net income of $13 million for the Electric reportable segment, as further discussed below;

Current wording

•a decrease in net income of $44 million for the Electric reportable segment, as further discussed below;

Previous wording

•an increase in net income of $15 million for Corporate and Other, primarily due to the favorable impact of accrued income tax benefits offset in other segments. This increase was partially offset by $14 million associated with increased borrowing costs.

Current wording

•a decrease in net income of $10 million for Corporate and Other, primarily due to a $27 million after-tax expense associated with increased borrowing costs, $8 million associated with a year-to-date tax benefit associated with the favorable impact of accrued income tax benefits offset in other segments in the first quarter of 2025, partially offset by a $21 million after-tax gain on early extinguishment of debt with proceeds from the divestiture of the Louisiana and Mississippi natural gas LDCs. See Note 3 and Note 9 for additional detail.

Previous wording

The following table provides variance explanations for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 by major income statement caption for CenterPoint Energy’s Electric reportable segment:

Current wording

The following table provides variance explanations for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 as well as for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 by major income statement caption for CenterPoint Energy’s Electric reportable segment:

Previous wording

The following table provides variance explanations for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 by major income statement caption for CenterPoint Energy’s Natural Gas reportable segment:

Current wording

The following table provides variance explanations for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 as well as for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 by major income statement caption for CenterPoint Energy’s Natural Gas reportable segment:

Previous wording

The following table provides variance explanations for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 by major income statement caption for Houston Electric:

Current wording

The following table provides variance explanations for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 as well as for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 by major income statement caption for Houston Electric:

Previous wording

The following table provides variance explanations for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 by major income statement caption for CERC:

Current wording

The following table provides variance explanations for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 as well as for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 by major income statement caption for CERC:

Previous wording

The following table summarizes the Registrants’ cash flows by category during the three months ended March 31, 2025 and 2024:

Current wording

The following table summarizes the Registrants’ cash flows by category during the six months ended June 30, 2025 and 2024:

Previous wording

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the three months ended March 31, 2025 compared to the three months ended March 31, 2024:

Current wording

Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities for the six months ended June 30, 2025 compared to the six months ended June 30, 2024:

Previous wording

Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities for the three months ended March 31, 2025 compared to the three months ended March 31, 2024:

Current wording

Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities for the six months ended June 30, 2025 compared to the six months ended June 30, 2024:

Previous wording

Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities for the three months ended March 31, 2025 compared to the three months ended March 31, 2024:

Current wording

Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities for the six months ended June 30, 2025 compared to the six months ended June 30, 2024:

Previous 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. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for the remainder of 2025 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. Future capital expenditures (other than expenditures associated with the May 2024 Storm Events) are expected to primarily relate to investment in infrastructure. These capital expenditures are anticipated to enhance 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 remainder of 2025 include the following:

Previous wording

The Registrants expect that anticipated cash needs for the remainder of 2025 will be met with available cash flow from operations, as well as cash flows from financing (such as incremental bond issuances including securitization, borrowings under credit facilities, commercial paper issuances or other sources) and investing activities (such as proceeds from divestitures). Such activities may include the issuance of securities in the capital markets as well as proceeds from divestitures. The issuance of securities in the capital markets and borrowings under additional credit facilities and term loans may not, however, be available on acceptable terms. The Registrants may also, 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.

Current wording

The Registrants expect that anticipated cash needs for the remainder of 2025 will be met with available cash flow from operations, as well as cash flows from financing (such as incremental bond issuances including securitization, issuances of equity securities upon physical settlement of outstanding forward sale agreements and borrowings under credit facilities, commercial paper issuances or other sources). At this time, CenterPoint Energy does not anticipate the need for further sales of shares of Common Stock under the Equity Distribution Agreement. The issuance of securities in the capital markets and borrowings under additional credit facilities and term loans may not, however, be available on acceptable terms. The Registrants may also, 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.

Previous wording

On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve an amended BTA to purchase the 191 MW Posey Solar project. 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. On March 7, 2025, SIGECO completed the acquisition of Posey Solar from Arevon for a purchase price of approximately $357 million. Subsequent to the acquisition, and pursuant to the Posey Solar Merger Agreement, Posey Solar was merged into SIGECO. The Posey Solar project is expected to be placed in service in the second quarter of 2025 and recovered through base rates. For further information, see Note 3 to the Interim Condensed Financial Statements.

Current wording

Indiana Electric has pursued PTCs for solar projects following the passage of the IRA. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve an amended BTA to purchase the 191 MW Posey Solar project. 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. On March 7, 2025, SIGECO completed the acquisition of Posey Solar from Arevon for a purchase price of approximately $357 million. Subsequent to the acquisition, and pursuant to the Posey Solar Merger Agreement, Posey Solar was merged into SIGECO. The Posey Solar project was placed in service in the second quarter of 2025 and is currently being recovered through base rates. In the applicable rate case, the IURC approved Indiana Electric’s request to convey PTCs to customers through the new tax adjustment rider. For further information, see Note 3 to the Interim Condensed Financial Statements.

Previous wording

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 is expected to 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 combined Form 10-Q, 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.

Current wording

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 the central region of MISO. Indiana Electric received approval from the IURC to recover the costs of the wind facility via the CECA mechanism, which is planned to be placed in service in 2027. 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 combined Form 10-Q, Indiana Electric has not entered into any definitive agreement relating to this wind energy generating facility, and there is a significant possibility that either no definitive agreement will be entered into at all or a definitive agreement will not be entered on the expected timeline.

Previous wording

Indiana Electric 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 and estimated interconnection cost increases, Indiana Electric and Clenera LLC have entered into discussions regarding the future of the project, which is expected to result in the termination of the PPA.

Current wording

Indiana Electric 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 and estimated interconnection cost increases, on April 24, 2025,

Previous 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 2028. As of March 31, 2025, Indiana Electric and Oriden had entered into additional discussions regarding the future of the solar project in Vermillion County, Indiana, which is expected to result in the termination of the PPA.

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 2028. On May 9, 2025, Indiana Electric and Oriden terminated the PPA.

Previous wording

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.

Current wording

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 mid-2026.

Previous wording

On April 14, 2025, Indiana Electric filed with the IURC seeking approval to purchase 170 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Tama County, Iowa. The facility is targeted to be in operation by the fourth quarter of 2025. Indiana Electric expects a decision from the IURC in the fourth quarter of 2025. If Indiana Electric’s request is approved, the power purchase costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA.

Current wording

On April 14, 2025, Indiana Electric filed with the IURC seeking approval to purchase 170 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Tama County, Iowa. On June 3, 2025, an amendment to the PPA was filed with the IURC requesting an extension of the PPA’s term from 25 to 27 years. The facility is targeted to be in operation by the fourth quarter of 2025. Indiana Electric expects a decision from the IURC in the fourth quarter of 2025. If Indiana Electric’s request is approved, the power purchase costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA.

Previous wording

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 is 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. It is expected that 230 MW of the facility will be operational in the second quarter of 2025, and, due to a transformer manufacturing issue, that the remaining 230 MW of the facility will be operational in the third quarter of 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. Indiana Electric received approval from the IURC on February 3, 2025, to recover for each combustion turbine by adjusting base rates as they are placed in service.

Current wording

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 was constructed and is 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. In the second quarter of 2025, 230 MW of the facility was placed in service, and, due to a transformer manufacturing issue, it is expected that the remaining 230 MW of the facility will be operational in the third quarter of 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. Indiana Electric received approval from the IURC on February 3, 2025, to recover for each combustion turbine by adjusting base rates as they are placed in service. The first turbine is currently being recovered in base rates that were updated on June 17, 2025.

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 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. Subsequently, on November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates. On April 21, 2025, the DOC announced its final affirmative determinations in the antidumping and countervailing duty investigations, determining that imports of silicon photovoltaic cells from the aforementioned countries are being dumped into the U.S. market and receiving countervailable subsidies. The International Trade Commission (the “ITC”) has until June 2, 2025 to make its final injury determination. If the ITC makes an affirmative country-specific final injury determination, the DOC will impose certain duty rates on imports of silicon photovoltaic cells from the aforementioned countries. Furthermore, in 2025, the U.S. government has announced and, in certain cases, rescinded, multiple tariffs on several foreign jurisdictions and imports into the United States. Increased tariffs by the United States have led, and may continue to lead, to the imposition of retaliatory tariffs or other measures taken by foreign jurisdictions, which may in turn lead to additional tariffs imposed or measures taken by the United States. These tariffs, as well as new legislation, tariffs, bans, retaliatory trade measures or related governmental action, have already, and may continue to, further negatively impact the supply of solar panels. In addition to supply reductions, these or similar duties, legislation, tariffs, bans 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. These impacts have resulted, and may continue to 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 …

Excerpt shortened here; the source contains the full paragraph.

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 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. On November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates. On April 21, 2025, the DOC announced its final affirmative determinations in the antidumping and countervailing duty investigations, determining that imports of silicon photovoltaic cells from the aforementioned countries are being dumped into the U.S. market and receiving countervailable subsidies. On May 20, 2025, the ITC announced its final determination that a U.S. industry is materially injured by reason of imports of silicon photovoltaic cells from Malaysia and Vietnam and a U.S. industry is threatened with material injury by reason of imports of silicon photovoltaic cells from Cambodia and Thailand. As a result of such determinations, the DOC will impose certain duty rates on imports of silicon photovoltaic cells from the aforementioned countries. Furthermore, in 2025, the U.S. government has announced and, in certain cases, rescinded, multiple tariffs on several foreign jurisdictions and imports into the United States. Increased tariffs by the United States have led, and may continue to lead, to the imposition of retaliatory tariffs or other measures taken by foreign jurisdictions, which may in turn lead to additional tariffs imposed or measures taken by the United States. These tariffs, as well as new legislation, tariffs, bans, retaliatory trade measures or related governmental action, have already, and may continue to, further negatively impact the supply of solar panels. In addition to supply reductions, these or similar duties, legislation, tariffs, bans 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. These impacts have resulted, and may continue to result in, cost increases for certain projects, and such impacts may require tha…

Excerpt shortened here; the source contains the full paragraph.

Previous wording

Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed a revised SRP with the PUCT on January 31, 2025 for review and approval. 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. Intervenor testimony was filed on April 8, 2025, and PUCT staff testimony was filed on April 15, 2025. All parties have agreed to mediation led by the State Office of Administrative Hearings on April 29, 2025. Houston Electric’s rebuttal is due by May 1, 2025. A hearing on the merits is scheduled for May 12, 2025 through May 14, 2025 and a decision from the PUCT is anticipated in the third quarter of 2025.

Current wording

Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed a revised SRP with the PUCT on January 31, 2025 for review and approval. The filed SRP proposed 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 proposed 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 was for transmission-related investments, and approximately $3.58 billion was for distribution-related investments. Intervenor testimony was filed on April 8, 2025, and PUCT staff testimony was filed on April 15, 2025. On June 12, 2025, Houston Electric announced that it had reached a settlement agreement with parties to its SRP, which provides for approximately $3.18 billion in distribution related investments. The proposed transmission investments were removed from the SRP and will be implemented as appropriate outside of the SRP process. The agreement also includes the deferral of more than $240 million of the approximate $3.18 billion in SRP costs until the second half of 2029, which will help reduce the bill impact for customers by spreading costs over a four-year period instead of three years. Once approved, and while some cost recovery would be deferred into 2029, it is expected that all SRP work agreed upon in the settlement agreement will be completed in the proposed 2025 to 2028 timeframe. A decision from the PUCT is anticipated in the third quarter of 2025.

Previous wording

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 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 ALJ filed a report on February 13, 2025 recommending that the MPUC approve the settlement agreement. As required by the December 20, 2024 order, the difference between 2024 interim rates and the settled amount of $60.8 million was refunded to customers in March 2025. Exceptions to the ALJ report were filed on April 18, 2025. The anticipated decision date of the rate case is July 1, 2025.

Current wording

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 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 ALJ filed a report on February 13, 2025 recommending that the MPUC approve the settlement agreement. As required by the December 20, 2024 order, the difference between 2024 interim rates and the settled amount of $60.8 million was refunded to customers in March 2025. Exceptions to the ALJ report were filed on April 18, 2025. On May 29, 2025, the MPUC approved the settlement agreement. A final order approving the settlement agreement was issued by the MPUC on June 27, 2025 and final rates are expected to be implemented on September 1, 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 was 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 was primarily driven by 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 reflected 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 then-current rates. Houston Electric reached a settlement agreement with certain parties and submitted the agreement to the PUCT on January 29, 2025. The settlement reflects a $47 million reduction in annual revenues and a 9.65% ROE and a weighted average cost of capital of 6.606% based upon an as-filed 4.29% cost of debt, an agreed ROE of 9.65% and an agreed regulatory capital structure of 56.75% long-term debt and 43.25% equity. A final order approving the settlement agreement was issued by the PUCT on March 13, 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 was 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 was primarily driven by 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 reflected 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 then-current rates. Houston Electric reached a settlement agreement with certain parties and submitted the agreement to the PUCT on January 29, 2025. The settlement reflects a $47 million reduction in annual revenues and a 9.65% ROE and a weighted average cost of capital of 6.606% based upon an as-filed 4.29% cost of debt, an agreed ROE of 9.65% and an agreed regulatory capital structure of 56.75% long-term debt and 43.25% equity. A final order approving the settlement agreement was issued by the PUCT on March 13, 2025. Final retail delivery rates were implemented on April 28, 2025. Final wholesale transmission rates were superseded by interim TCOS rates that went into effect on the same date.

Previous wording

Ohio Gas Rate Case. 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 an equity percentage of 45.87%. The need for a rate increase was primarily driven by 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.

Current wording

Ohio Gas Rate Case. 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 an equity percentage of 54.13%. The need for a rate increase was primarily driven by continuing investment in the safety and reliability of the natural gas system. On May 16, 2025, the PUCO staff filed its staff report recommending a revenue requirement range of $340.8 million to $350.3 million and a net increase of $25.1 million to $34.6 million based on an ROE range from 9.05% to 10.07% with a capitalization ratio of 52.3% common equity and 47.7% long-term debt. The PUCO staff recommendation includes amortization over 49 years and 65 years for CEP and DRR assets, respectively, compared to CEOH’s proposal to amortize over seven years. On June 16, 2025, CEOH filed objections to the PUCO staff report and supplemental testimony. On July 11, 2025, CEOH filed a stipulation and recommendation that outlined the agreed upon terms between CEOH, the Federal Executive Agencies, Ohio Energy Group, the City of Dayton, the Retail Energy Supply Association, Interstate Gas Supply, LLC and the PUCO staff. One intervening party to the case, Spire Marketing, Inc., is a non-opposing party, while another intervening party to the case, the Office of the Ohio Consumers’ Counsel, did not sign onto, and has indicated that it plans to oppose, the stipulation and recommendation. The stipulation and recommendation included a revenue requirement of $371.3 million, which would result in a revenue requirement increase of $59.6 million based on a rate of return of 7.1% comprised of a ROE of 9.85% with a capitalization ratio of 52.9% common equity, 47.1% long-term debt at a cost of debt of 4.02%. The stipulation and recommendation amortization periods for CEP and DRR assets within base rates and within the rider mechanisms is 15 years. The stipulation and recommendation included an extension of the CEP rider and DRR through 2029 investment with revised residential caps for dollars per month per customer ranging from $2.75 for 2025 investment to $9.95 for 2029 investment for the CEP rider, and from $2.56 for 2025 investment to $7.69 for 2029 investment for DRR. The evidentiary hearing commenced on July 21, 2025 and is scheduled to continue until early August. A final order is expected no sooner than the first quarter of 2026.

Previous wording

There has been increasing attention at the local, state and international levels to the issue of climate risk. There has been a recent shift, however, in climate policy at the federal level in the United States. On January 20, 2025, President Trump signed an executive order to withdraw the United States from the Paris Agreement, which 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 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 response to the series of executive orders, on March 12, 2025, the EPA announced 31 regulatory actions, including the reconsideration of certain regulations and standards under the Clean Air Act and other air-related rules such as the 2009 endangerment finding authorizing the EPA to regulate GHG emissions under the Clean Air Act, the mandatory GHG Reporting Program, GHG emissions limits for the oil and gas sector adopted by the prior administration, and the rules regulating GHG emissions from new gas-fired combustion turbines and existing coal, oil and gas-fired steam generating units. On March 14, 2025, President Trump signed a Joint Resolution of Disapproval under the Congressional Review Act to prohibit the IRA’s waste methane emissions charge rules, which were finalized in November 2024, from taking effect.

Current wording

There has been increasing attention at the local, state and international levels to the issue of climate risk. There has been a recent shift, however, in climate policy at the federal level in the United States. On June 11, 2025, the EPA proposed to repeal all GHG emissions standards for the power sector under Section 111 of the Clean Air Act. As an alternative, the EPA proposed to repeal a narrower set of requirements, including the emission guidelines for existing fossil fuel-fired steam electric generating units and the carbon capture and sequestration/storage-based standards for new base load stationary combustion turbines.

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. Litigation challenging the rules was filed by multiple parties in multiple jurisdictions, which was consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC announced it was voluntarily delaying the implementation of the climate disclosure rules while the U.S. Court of Appeals considered the litigation, and on March 27, 2025, the SEC voted to end the defense of the rules in the litigation.

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. Litigation challenging the rules was filed by multiple parties in multiple jurisdictions, which was consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On April 4, 2024, the SEC announced it was voluntarily delaying the implementation of the climate disclosure rules while the U.S. Court of Appeals considered the litigation, and on March 27, 2025, the SEC voted to end the defense of the rules in the litigation. On April 4, 2025, a group of 18 intervenor-respondent states and the District of Columbia moved to hold the cases in abeyance until the SEC amends or rescinds the regulations, which motion was granted by the U.S. Court of Appeals in an order issued on April 24, 2025. Further, the U.S. Court of Appeals directed the SEC to file a status report within 90 days (by July 23, 2025) advising the court whether the SEC intends to review or reconsider the rules at issue in the case.

Previous wording

Recent changes in the U.S. presidential administration and significant expected increases in electric demand, as announced by organizations such as ERCOT and MISO, have shifted the energy landscape in the United States. Since taking office, President Trump has issued a series of executive orders and presidential memoranda that seek to increase investment in fossil fuel infrastructure, including by directing all heads of federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are determined to be unduly burdensome on the identification, development or use of domestic energy resources, with particular attention to oil, natural gas, hydropower, biofuels, critical mineral and nuclear energy resources. This shift in federal domestic energy policy has resulted in uncertainty with respect to the scope and speed of future renewable generation infrastructure development and the role that existing renewable generation will play in support of the U.S. energy grid. The long-term impacts of this domestic energy policy shift are uncertain, including with respect to impacts on the regulatory framework relating to the development of, and consequently the availability of, alternative energy sources (such as private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices). Additionally, it is unclear whether, and if so how, the new domestic energy policy, including the potential suspension, revision or rescission of regulations restricting emissions (including methane emissions), will affect consumers’ and companies’ energy use, adoption of alternative energy sources or decisions to expand their facilities, including natural gas facilities.

Current wording

Changes in the U.S. presidential administration and significant expected increases in electric demand, as announced by organizations such as ERCOT and MISO, have shifted the energy landscape in the United States. Since taking office, President Trump has issued a series of executive orders and presidential memoranda that seek to increase investment in fossil fuel infrastructure, including by directing all heads of federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are determined to be unduly burdensome on the identification, development or use of domestic energy resources, with particular attention to oil, natural gas, hydropower, biofuels, critical mineral and nuclear energy resources. Additionally, on July 4, 2025, the OBBBA was signed into law, which includes numerous changes to the energy tax credits initially introduced and expanded under the IRA, including accelerated phase outs for certain credits. Further, on July 7, 2025, President Trump issued Executive Order 14315, which relates to the implementation of such changes to energy tax credits. This shift in federal domestic energy policy has resulted in uncertainty with respect to the scope and speed of future renewable generation infrastructure development and the role that existing renewable generation will play in support of the U.S. energy grid. The long-term impacts of this domestic energy policy shift are uncertain, including with respect to impacts on the development of, and consequently the availability of, alternative energy sources (such as solar energy, including private solar, wind energy, microturbines, fuel cells, energy-efficient buildings and energy storage devices). Additionally, it is unclear whether, and if so how, the new domestic energy policy, including the potential suspension, revision or rescission of regulations restricting emissions (including methane emissions), will affect consumers’ and companies’ energy use, adoption of alternative energy sources or decisions to expand their facilities, including natural gas facilities.

Previous wording

The borrowers are currently in compliance with the various business and financial covenants in the four revolving credit facilities.

Current wording

The Registrants and SIGECO are currently in compliance with the various business and financial covenants in the four revolving credit facilities.

Previous wording

Additionally, for information related to shares of Common Stock sold pursuant to the Equity Distribution Agreement in 2025, see Note 15 and Note 16 to the Interim Condensed Financial Statements.

Current wording

Additionally, for information related to shares of Common Stock sold pursuant to the forward sale agreements and the Equity Distribution Agreement in 2025, see Note 15 to the Interim Condensed Financial Statements.

Previous wording

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 up to $314 million as of March 31, 2025. The amount of collateral will depend on seasonal variations in transportation levels.

Current wording

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 up to $289 million as of June 30, 2025. The amount of collateral will depend on seasonal variations in transportation levels.

Previous 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 March 31, 2025, deferred taxes of approximately $806 million would have been payable in 2025. If all the ZENS-Related Securities had been sold on March 31, 2025, capital gains taxes of approximately $99 million would have been payable in 2025 based on 2025 tax rates in effect. For additional information about ZENS, see Note 8 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, 2025, deferred taxes of approximately $819 million would have been payable in 2025. If all the ZENS-Related Securities had been sold on June 30, 2025, capital gains taxes of approximately $108 million would have been payable in 2025 based on 2025 tax rates in effect. For additional information about ZENS, see Note 8 to the Interim Condensed Financial Statements.

Previous wording

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 for approximately $1.2 billion, 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 closed on March 31, 2025. On March 7, 2025, SIGECO acquired 100% of the equity interests in Posey Solar, which is constructing a 191 MW solar array in Posey County, Indiana, for approximately $357 million. For further information, see Note 3 to the Interim Condensed Financial Statements.

Current wording

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 for approximately $1.2 billion, 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 closed on March 31, 2025. On March 7, 2025, SIGECO acquired 100% of the equity interests in Posey Solar, which was constructing a 191 MW solar array in Posey County, Indiana, for approximately $357 million. For further information, see Note 3 to the Interim Condensed Financial Statements. In May 2025, CenterPoint Energy announced that it is planning to sell its Ohio natural gas LDC business to support the efficient recycling of capital and portfolio optimization.

Previous wording

•various legislative, executive or regulatory actions at the federal, state and local levels, including such actions in response to the May 2024 Storm Events and Hurricane Beryl;

Current wording

•various legislative, executive or regulatory actions at the federal, state and local levels, including actions in response to the May 2024 Storm Events and Hurricane Beryl and actions pertaining to trade (including tariffs, bans, retaliatory trade measures taken against the United States or related governmental action);

Previous wording

A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require the Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. Our critical accounting policies that we deemed the most material in nature were reported in our combined 2024 Form 10-K. There has been no material changes with regard to these critical accounting policies.

Current wording

A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. Our critical accounting policies that we deemed the most material in nature were reported in our combined 2024 Form 10-K. There has been no material changes with regard to these critical accounting policies.