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We are a holding company whose principal businesses are regulated utilities in California and Texas. 10-K, Item 1
38 paragraphs in Risk Factors of the 10-K filed Feb 26, 2026 with nothing like them in the 10-K filed Feb 25, 2025. Quoted exactly. Paragraphs that were only edited are under 10-K change.
Compared with the Risk Factors in the latest 10-K of the other 30 Utilities companies: a paragraph with at least half its words the same at another company is called similar, and the companies are listed under it. A paragraph most of them have is marked boilerplate. No line means no other company has one like it. This counts text; it does not say how serious a risk is.
Our facilities and the systems that interconnect and/or manage them are subject to risks of, among other things:
▪shortages of or delays in obtaining equipment, materials, supplies, commodities or labor, which have been and may continue to be exacerbated by supply chain and gas transportation capacity constraints, tight labor markets, and cost increases due to inflation, tariffs or otherwise, that may not be recoverable in a timely manner or at all
▪operational restrictions resulting from governmental interventions, including environmental requirements, or permitting delays
▪inability to enter into, maintain, extend or replace long-term supply or transportation contracts
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We face evolving cybersecurity, technology resiliency and data security and governance risks, including with respect to increasing use of artificial intelligence.
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In addition to security and privacy risks related to data, we face challenges related to data governance, including the need to manage our data with the aim to meet regulatory requirements and create a foundation for the use of artificial intelligence tools. Our current and potential future uses of such tools (and use by our vendors and agents) may expose us to heightened security and privacy risks as well as operational, legal, and reputational risks. Data produced by or contained in artificial intelligence tools may contain inaccuracies, and our investments in such technologies and related organizational changes may not deliver the expected benefits, which could result in operational disruptions, inefficiencies, unexpected costs and regulatory disallowances. Beginning in January 2027, our businesses that are subject to the California Consumer Privacy Act will also be subject to new regulations related to, among other things, the use of artificial intelligence tools to automate certain decisions. These regulations may limit some potential applications of such technologies, particularly with respect to previously collected personal data. The regulations require companies to disclose any covered use of such technologies and how the relevant decisions will be made and to allow consumers to opt out of such use, subject to limited exceptions. The regulations also require companies to conduct risk assessments before initiating certain data processing activities, disclose information about these assessments to the California Privacy Protection Agency, conduct an annual cybersecurity audit and submit a written compliance certification to the agency.
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Conditions in global markets, including the impact of enacted and proposed tariffs and other trade actions, may materially and adversely affect us.
Our businesses import various materials, including steel and aluminum, and purchase foreign-sourced goods, such as electrical transformers, from domestic distributors. SI Partners also generates a material portion of its earnings from LNG exports to customers located outside the U.S., including countries in Asia and Europe. Our ability to continue importing materials and purchasing foreign-sourced goods at competitive prices and reaching positive FIDs on LNG and other projects in development is subject to a number of risks, including adverse impacts on the affordability of projects in development and under construction due to the imposition of tariffs by the U.S. Administration, and adverse impacts caused by (i) legal and regulatory requirements or limitations imposed by foreign governments, including tariffs, quotas or other trade barriers, sanctions, adverse tax law changes, nationalization, currency restrictions, or import restrictions, and (ii) disruptions or delays in shipments caused by customs compliance or other actions of government agencies.
In 2018, the U.S. imposed tariffs on certain imported steel and aluminum products, as well as tariffs in various ranges on imports from China. Those tariffs remain in effect. Beginning in January 2025, the U.S. Administration has announced a number of new and increased tariffs, both threatened and imposed, including a higher total tariff rate on goods from China and numerous other tariffs on imports from all countries with only limited exclusions. The U.S. Administration has delayed the effectiveness of certain tariffs and tariff rate increases and threatened to accelerate the effectiveness of others. In particular, the U.S. Administration has imposed new tariffs on Mexico and Canada, and additional tariffs have been threatened and these and other changes, including in connection with the planned joint review of the U.S.-Mexico-Canada Agreement in 2026, may become effective in the near term. Additionally, the U.S. Administration has expanded the application of the 2018 steel and aluminum tariffs to countries and products that had previously been excluded, including a broad range of derivative products, increased steel and aluminum tariff rates, and imposed tariffs on certain imported copper products. The U.S. Administration also is considering new tariffs on additional imported products, including power grid equipment, large-scale batteries and plastic piping. These threatened and imposed tariffs have created uncertainty in our business development efforts and for projects currently under construction, and we expect them to impact our businesses’ costs related to construction, pipeline transportation, electricity procurement and financing, among other areas, and increase costs across the LNG value chain. These impacts may result in delays, cost overruns or reduced profitability for construction and development projects, denials or delays of recovery in rates of higher costs at our regulated utilities, or other adverse effects, any of which could be material.
We also face uncertainty in the interpretation and application of these tariffs, including with respect to customs valuation, product classification and country-of-origin determinations. Any disagreement with regulators on these matters could result in the retroactive assessment of additional tariffs with interest, the imposition of penalties, or other enforcement actions, any of which could be material.
These recent tariffs, along with other U.S. trade actions, have triggered retaliatory actions by certain affected countries, including China’s announcement of a tariff on U.S. LNG. The Mexican government has announced it may implement retaliatory tariffs in response to the U.S. Administration’s tariffs, and other foreign governments may also impose trade measures, including retaliatory tariffs, on LNG or other U.S. goods in the future. These tariffs and other trade actions could negatively impact demand for our LNG exports, which would adversely impact our LNG projects and development pipeline.
While the U.S. Administration has announced various trade deals, many such agreements are preliminary and may be subject to change. Certain of the announced deals, including the agreement with the European Union, require further governmental approvals, and certain announced deal terms, including purported commitments by the European Union and Japan to purchase more U.S. energy, may be non-binding or subject to voluntary implementation by the private sector. Any disagreement between the U.S. and other countries over the implementation of such trade deals or any failure to obtain required governmental approvals or otherwise reach a final agreement could result in prolonged uncertainty regarding the scope and duration of these trade actions by the U.S. and other countries. Such actions and any resulting economic, financial or geopolitical instability could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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We discuss these credit ratings in “Part II – Item 7. MD&A - Capital Resources and Liquidity.”
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The industries in which we operate are subject to extensive regulation, increasing regulatory uncertainty and political influence and polarization.
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▪for our regulated utilities, expenditures are required before rate recovery can be requested or remain subject to subsequent regulatory filings and/or reasonableness reviews that could result in extended delays or denial of rate recovery or disallowance of some or all incurred costs
Our businesses engage in lobbying at the federal, state and local levels with the aim to support sound and stable governmental policies and shape the legal and regulatory framework for the energy sector. As has happened in the past, these advocacy efforts may be unsuccessful or result in adverse publicity. We also incur costs related to these activities, and for our regulated utilities, such costs are not recoverable in rates. Any of these impacts could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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The LA Fires burned in SoCalGas’ service territory. The California Department of Forestry and Fire Protection estimates that the Palisades and Eaton fires destroyed approximately 16,200 structures and damaged approximately 2,000 structures. Although the majority of SoCalGas’ infrastructure in the fire-affected areas is underground, these fires resulted in service disruptions, response costs and damage to some of SoCalGas’ infrastructure and third-party property. SoCalGas and Sempra are subject to pending litigation with respect to the operation of SoCalGas’ system and damage sustained as a result of the fires, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. As with other litigation, the timing, impacts and ultimate outcome of these matters is inherently uncertain and may result in substantial costs, some or all of which may not be recoverable from insurance, third parties or in customer rates. We discuss these and other risks associated with litigation above under “Risks Related to All Sempra Businesses – Operational Risks.”
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In February 2026, a participating IOU publicly disclosed that it has received, or expects to receive, approximately $1.26 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021. Also in February 2026, another participating IOU publicly disclosed it has received, or expects to receive, approximately $134 million in aggregate reimbursements from the Wildfire Fund for losses incurred and expected to be incurred in connection with one of the LA Fires, the cause of which remains under investigation and has not been conclusively determined. The administrator of the Wildfire Fund has confirmed that this wildfire qualifies as a “covered wildfire” for purposes of accessing the Wildfire Fund, and the scope of potential damages caused by this fire could materially reduce or exhaust the Wildfire Fund. The participating IOU stated that it is currently unable to reasonably estimate a range of potential losses associated with this event. Accordingly, SDG&E is unable to estimate a range of potential loss resulting from any reduction in available coverage from the Wildfire Fund. In addition to the risks described above, a material reduction, exhaustion or termination of the Wildfire Fund may require SDG&E to recognize a reduction to its Wildfire Fund asset up to its carrying value.
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The 2025 Wildfire Legislation also established a multi-stakeholder task force, coordinated by the Wildfire Fund’s administrator, to prepare and submit to the California legislature and Governor of California on or before April 1, 2026, a report that evaluates and sets forth recommendations on new models to complement or replace the Wildfire Fund and, if it becomes operative, the Continuation Account. We are unable to predict the impact on Sempra or SDG&E of further legislative or regulatory action with respect to the Wildfire Fund or the Continuation Account or wildfire claims liability generally.
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Additionally, if a CCA or DA in SDG&E’s service territory were to fail, SDG&E, as the provider of last resort, would be responsible for providing uninterrupted electric service to customers and would be entitled to cost recovery for temporary service, and the CCA or DA would be required to post financial security to cover the cost of returning load. Once returned, SDG&E would be required to provide commodity service to those customers and would be required to meet the increased commodity compliance requirements resulting from service of the additional load. The CPUC has established an application process for non-IOU load serving entities to potentially step into the role of provider of last resort. If a non-IOU load serving entity was permitted to serve as provider of last resort in SDG&E’s service territory, SDG&E may not be responsible for providing commodity service from the failure of a CCA or DA, the impact of which remains uncertain. Any of these outcomes could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
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The FERC enforces mandatory reliability standards developed by the North American Electric Reliability Corporation, including standards designed to protect the power system against potential disruptions from cyber and physical security breaches. Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1.6 million per day per violation) for any failure to comply with these standards, which could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
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Additionally, projected load growth across the ERCOT system could, if not sufficiently addressed through generation resources, system design and reliability measures, negatively impact electric infrastructure reliability and potentially cause system-wide stresses, which may be exacerbated by extreme weather events, climate-related conditions, wildfires, cyberattacks and other emergencies. Oncor is not a generator of electricity and has no control over the generation supply in ERCOT. If electricity generation is inadequate or disrupted, Oncor’s electricity delivery services may be interrupted or diminished, which could have an adverse impact on our results of operations, financial condition, cash flows and/or prospects.
Oncor is subject to periodic audits of its compliance with operations and critical infrastructure protection standards, including reliability and cybersecurity standards, as well as periodic inspections of its facilities for compliance with weatherization standards. Oncor is also required to report to the PUCT on its reliability and weather preparedness. If Oncor is found to be noncompliant with applicable reliability, service quality, weatherization or other standards, it could be subject to reputational harm, regulatory scrutiny or sanctions, including monetary penalties.
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Oncor’s capital expenditures plan may not be executed as planned or achieve its business objectives.
Oncor’s capital expenditures plan may not be successful or completed in accordance with currently forecasted amounts, and the capital expenditures Oncor currently intends to make may not be implemented as contemplated or produce the desired improvements to service and reliability or cost management. A significant portion of Oncor’s five-year capital expenditures plan is attributable to addressing expected growth in ERCOT. Changes to the timing, location or scope of these planned projects or to the overall projected demand growth in Oncor’s service territory could materially impact Oncor’s capital expenditures plan and consequently our capital expenditures plan, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Oncor’s capital expenditures plan contemplates the large-scale buildout of new transmission lines, including the planned introduction of the 765-kV voltage class to the ERCOT market through ERCOT’s 765-kV Strategic Transmission Expansion Plan. In addition, Oncor’s capital expenditures plan includes projects to service increasing amounts of transmission interconnection requests from LC&I customers, including data centers. Data center development in Oncor’s service territory is expected to drive increasing electric demand and require a rapid and significant increase in Oncor’s grid infrastructure. The resources required to serve these new LC&I requests, including activities related to the planning, analysis, financing, and construction of transmission infrastructure required to meet the projected demand of these customers, are significant in terms of both cost and time, and Oncor may not be able to effectively or efficiently plan, receive required regulatory approvals for, finance, and execute on these requests. Additionally, forecasting future demand involves the risk that one or more high-usage customers may decide not to take energy, to take less energy than anticipated, or not to take service on the anticipated schedule, which may result in lower than expected demand growth. In addition, various statutes, regulatory requirements, and ERCOT rules and policies increasingly govern the connection of new LC&I customers to the grid and these regulations and procedures are under significant and rapidly evolving scrutiny, development and modification. How these provisions are ultimately implemented could significantly impact the desirability of the ERCOT market to prospective customers or Oncor’s ability to interconnect projects on their requested timelines. Certain of these new customers may be transitory and exit Oncor’s service territory for reasons outside of Oncor’s control.
If expected projects in Oncor’s service territory are cancelled or do not materialize or actual demand is lower than projected for any of the reasons described above or any others, Oncor’s ability to obtain cost recovery from the PUCT for related expenditures or the affordability of Oncor’s customer rates may be adversely impacted, which could materially adversely impact our results of operations, financial condition, cash flows and/or prospects.
Oncor’s capital expenditures plan will result in significant liquidity needs that may necessitate additional investments.
Oncor’s business is capital-intensive, with significant expected increases to capital spending in future periods.
Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the past, Oncor has financed much of its cash needs from operations and with proceeds from indebtedness, but these sources of capital may not be adequate or available in a timely manner, on reasonable terms or at all. Oncor’s access to capital and credit markets and its cost of debt could be directly affected by changes to its credit ratings or ratings outlook. Adverse action with respect to Oncor’s credit ratings or ratings outlooks generally causes debt issuance and borrowing costs to increase. Moreover, legislative, regulatory, market or industry activities could negatively impact Oncor’s credit ratings or ratings outlooks. For example, rating agencies have noted concern that, in Texas, regulators have mandated equity ratios significantly lower than the national average for rate-making purposes. Additionally, in July 2025, S&P lowered Oncor’s senior secured debt and commercial paper ratings, citing elevated wildfire risk as a result of changing climate conditions and the lack of certain legal protections for wildfire litigation in Texas.
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▪implementation of new or changes to existing laws or regulations, including increasing influence of the Mexican government on economic and energy matters and risks related to laws and regulation in Mexico generally, which we discuss further in the risk factors below
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As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” SI Partners enters into hedging transactions to help mitigate commodity price risk and optimize the value of its LNG, natural gas pipelines and storage, and power-generating assets. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility, which may be material, as the economic offset of these derivatives may not be recorded at fair value.
If the CRNCI becomes redeemable, SI Partners may not have sufficient funds available to fulfill its obligation of redemption.
Blackstone’s equity interest represents an NCI in PA2 JVCo and is classified as contingently redeemable because Blackstone has certain redemption and exit rights that are outside the control of SI Partners. These rights include, among others, the ability to require redemption upon (i) failure to complete construction by a specified date; (ii) sustained priority distributions to Blackstone above specified thresholds and for specified time periods as a result of extended periods of operational underperformance exceeding certain thresholds, termination of LNG offtake contracts that have not been replaced within a specified timeframe, or material breach of certain affiliate contracts; or (iii) the occurrence of certain monetization events, including a third-party sale of PA2 JVCo. Because these redemption features are contingent on events not solely within SI Partners’ control, we present Blackstone’s equity interest as a CRNCI. If the CRNCI becomes redeemable, SI Partners may not have sufficient funds available to fulfill its obligation of redemption to satisfy Blackstone’s redemption right.
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In 2024, the Mexican government adopted changes to the Mexican Constitution to reinforce state control over strategic sectors by granting a central role to government entities like the CFE and PEMEX, which have been converted from for-profit state-owned enterprises into public state-owned enterprises. Following these constitutional reforms, in March 2025, the Mexican government adopted the 2025 Energy Laws, which increase the government’s control and participation in the energy sector and may create novel challenges for infrastructure development and operations. Like the LIE and LH, the 2025 Energy Laws give Mexican authorities broad discretion to revoke or suspend permits under certain circumstances. In October 2025, the Mexican government enacted new regulations regarding the 2025 Energy Laws, which provide further detail on the legal and regulatory framework of the energy sector. These new regulations provide state-owned companies preferential treatment regarding open access, increase oversight by regulators and obligations for private companies and reduce the maximum term of certain permits for new projects. For the power sector, the new regulations provide for state prevalence and additional requirements for private projects, increase oversight by regulators and sanctions and establish that self-supply permits remain valid and can migrate voluntarily to the wholesale electricity market. Additionally, in December 2025, the Mexican government released proposed regulations that could adversely impact our self-supply power plants and the development of new power export projects by potentially increasing tariff rates and thereby reducing the competitiveness of projects operating under the self-supply framework.
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We may be unable to complete or realize the anticipated benefits from our planned sales of certain of our assets and businesses as part of our capital recycling program.
As we discuss in Note 6 of the Notes to Consolidated Financial Statements, in September 2025, we entered into an agreement to sell a 45% equity interest in SI Partners to the KKR Partners for $9.99 billion, subject to adjustments. We expect this sale to close in the second or third quarter of 2026, subject to certain conditions, including receipt of antitrust approvals in Mexico; receipt of other third-party consents or waivers, including from certain lenders, partners and others; the absence of a material adverse effect on SI Partners; the absence of specific downgrade events under certain financing arrangements; and other customary closing conditions. Additionally, in December 2025, we entered into an agreement to sell Ecogas. We expect to complete the sale of Ecogas in the second or third quarter of 2026, subject to closing conditions. These pending sales may not be completed in a timely manner or at all. Applicable regulatory authorities and other third parties may withhold the necessary approvals, seek to block or challenge the transactions in the case of certain regulatory authorities, or impose burdensome or costly requirements as conditions to approval. If the required approvals or consents are not received, the other closing conditions are not satisfied or waived, or any of the foregoing is not achieved in a timely manner or on satisfactory terms, then we may need to incur additional costs to complete these transactions, which costs could be significant, or the transactions may be abandoned, delayed or restructured, which would prevent us from realizing the potential benefits of the transactions while still bearing the substantial costs incurred to pursue them.
Even if they close, any efficiencies and benefits we expect from these transactions, including with respect to our capital recycling program, might be delayed or not realized. Our expectations are based on a number of assumptions, estimates, projections and other uncertainties about, among other things, closing and post-closing payments; purchase price adjustments; transaction-related tax and accounting impacts; performance by the KKR Partners of their respective contractual obligations; transition services and employee matters; the results of operations of SI Partners after the closing of the proposed transactions; and other factors beyond our control. Moreover, the planned decrease in our ownership of SI Partners would also decrease our share of the cash flows, profits and other benefits from this business. Additionally, the KKR Partners collectively would generally have control of SI Partners, subject to certain minority consent rights so long as the minority partners maintain specified ownership thresholds. The KKR Partners may not manage SI Partners in accordance with our current expectations, which could materially adversely affect the value of our minority ownership interest.
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84 paragraphs in the 10-Q filed Nov 5, 2026 with nothing like them in the 10-Q filed Aug 6, 2026 (at least half the words must differ; new numbers alone do not count). Quoted exactly, grouped by the item heading above them. This is text that changed, not a judgement of how serious it is.
At September 30, 2026, the carrying value of SDG&E’s Wildfire Fund asset totaled $ 239 million.
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SDG&E is amortizing the Wildfire Fund asset on a straight-line basis over the estimated period of benefit of 25 years, as adjusted for utilization by the other participating IOUs, PG&E and Edison. SDG&E recognizes a reduction of its Wildfire Fund asset and records a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, decrease the Wildfire Fund asset and remaining available coverage. SDG&E periodically evaluates the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in assumptions, including relying on publicly disclosed wildfire-related losses incurred by the other participating IOUs.
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In October 2026, PG&E publicly disclosed that it has received, or expects to receive, approximately $ 1.38 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021.
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SDG&E reduced its Wildfire Fund asset by recording $ 5 million and $ 10 million in the three months and nine months ended September 30, 2026, respectively, and $ 2 million in the three months and nine months ended September 30, 2025, of accelerated amortization in O&M on Sempra’s and SDG&E’s Condensed Consolidated Statements of Operations.
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We recognized the following amounts related to our investments in SI Partners and Ecogas in Income Tax Expense on Sempra’s Condensed Consolidated Statements of Operations:
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▪ income tax expense of $ 59 million from the gain on sale of Ecogas in August 2026, which we discuss in Note 6
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The OBBBA includes revisions to tax credits and other incentives for energy and climate initiatives of the Inflation Reduction Act enacted in 2022 and extends or revises key provisions of the TCJA, among other changes. Effective January 1, 2025, we have adopted the provisions of OBBBA, which include immediate expensing of domestic research and experimental expenditures, including utility self-developed software expenditures, under the new Internal Revenue Code Section 174A. This change supersedes prior rules requiring five-year amortization of domestic research and experimental expenditures under the TCJA. In accordance with IRS transitional guidance (Revenue Procedure 2025-28), we elected to accelerate deductions evenly over 2025 and 2026 for domestic unamortized utility self-developed software expenditures incurred in tax years 2022-2024. As a result, Sempra, SDG&E and SoCalGas recorded an income tax benefit of $ 73 million, $ 26 million and $ 47 million, respectively, in the three months and nine months ended September 30, 2025, with remaining balances deductible in 2026.
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DISAGGREGATED REVENUES (Dollars in millions) SDG&E SoCalGas Three months ended September 30, 2026 2025 2026 2025 By major service line: Revenues from contracts with customers – Utilities $1,683 $1,349 $1,101 $1,217 By market: Gas $190 $218 $1,101 $1,217 Electric 1,493 1,131 — — Revenues from contracts with customers $1,683 $1,349 $1,101 $1,217 Revenues from contracts with customers $1,683 $1,349 $1,101 $1,217 Utilities regulatory revenues (73) 131 70 (36) Total revenues $1,610 $1,480 $1,171 $1,181 Nine months ended September 30, 2026 2025 2026 2025 By major service line: Revenues from contracts with customers – Utilities $4,626 $3,851 $4,042 $4,706 By market: Gas $694 $789 $4,042 $4,706 Electric 3,932 3,062 — — Revenues from contracts with customers $4,626 $3,851 $4,042 $4,706 Revenues from contracts with customers $4,626 $3,851 $4,042 $4,706 Utilities regulatory revenues (101) 311 44 (237) Total revenues $4,525 $4,162 $4,086 $4,469
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September 30, December 31, September 30, December 31, September 30, December 31,
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(4) Includes decreases of $ 38 and $ 111 in 2026 at SDG&E and SoCalGas, respectively, from regulatory disallowances associated with the Track 3 PD and $ 92 in 2026 at SoCalGas from regulatory disallowances associated with the Transmission Integrity Management Program PD.
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(5) Includes a $ 222 increase in 2026 from the reversal of a portion of regulatory disallowances as a result of SDG&E’s Track 3 PD and a $ 508 decrease in 2025 from regulatory disallowances associated with SDG&E’s Track 2 FD.
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In September 2026, the CPUC issued a PD authorizing an $ 82 million revenue requirement, compared with the $ 174 million requested by SoCalGas, for costs associated with the 2019 GRC cycle for integrity assessments and repairs associated with federal regulatory changes. In the third quarter of 2026, SoCalGas recorded a charge of $ 92 million ($ 66 million after tax) in Regulatory Disallowances, Net, on the Condensed Consolidated Statements of Operations, of which $ 91 million ($ 66 million after tax) relates to prior years and $ 1 million relates to 2026.
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On October 29, 2026, the CPUC approved a revised PD that reduces the disallowance of capital and O&M costs by approximately $ 30 million, and allows SoCalGas to propose an alternative allocation of the disallowance between capital and O&M costs. SoCalGas is required to submit an advice letter within 30 days of the FD’s effective date to calculate the final revenue requirement. As a result, the charge SoCalGas recorded in the third quarter of 2026, pursuant to the PD, may change based on the approved advice letter. SoCalGas expects to file the advice letter in the fourth quarter of 2026.
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Separately, SDG&E and SoCalGas submitted a combined Track 3 request seeking review and recovery of $ 240 million and $ 499 million, respectively, of PSEP costs. SDG&E incurred its PSEP costs from 2014 through 2019, and SoCalGas incurred its PSEP costs from 2015 through 2020. In September 2026, the CPUC issued a PD authorizing revenue requirements through 2026 of $ 210 million for SDG&E and $ 361 million for SoCalGas. SDG&E and SoCalGas expect the CPUC to issue an FD in the fourth quarter of 2026. Through 2026, SDG&E and SoCalGas are authorized to collect $ 193 million and $ 341 million, respectively, in rates under an interim cost recovery mechanism approved by the CPUC in 2016. The Track 3 PD authorizes SDG&E and SoCalGas to collect the remaining $ 17 million and $ 20 million, respectively, in 2027.
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As a result of these PDs in the Track 3 requests, SDG&E recorded a credit in the third quarter of 2026 to Regulatory Disallowances, Net, of $ 104 million ($ 72 million after tax), of which $ 98 million ($ 67 million after tax) relates to prior years and $ 6 million ($ 5 million after tax) relates to 2026. The credit consists of the reversal of a portion of the $ 651 million ($ 464 million after tax) regulatory disallowance charge recognized in the fourth quarter of 2025, partially offset by an additional regulatory disallowance charge recognized in the third quarter of 2026. SoCalGas recorded a charge in the third quarter of 2026 to Regulatory Disallowances of $ 217 million ($ 157 million after tax), of which $ 209 million ($ 150 million after tax) relates to prior years and $ 8 million ($ 7 million after tax) relates to 2026.
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▪ the purchase price, subject to adjustments at closing, including (i) adjustments to reflect SI Partners’ net debt, net working capital and capital expenditures as of or through December 31, 2025; (ii) adjustments for certain capital contributions by and distributions to Sempra in 2026 before closing; (iii) costs related to transaction consents; (iv) a ticking fee of 0.625 % per month on the aggregate base purchase price that accrues daily beginning April 1, 2026; (v) $ 338 million of transaction fees reimbursed by Sempra to the KKR Partners; and (vi) other transaction costs
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▪ the estimated fair value of Sempra’s retained 25 % equity interest in SI Partners
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▪ estimated carrying values of SI Partners’ net assets, CRNCI, AOCI, NCI, and interest capitalized at Parent and other as of the closing date
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▪ a $ 340 million credit payable by Sempra for the KKR Partners’ share of development costs through 2027
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▪ the estimated fair value of Sempra’s indemnification obligations to the KKR Partners for potential losses associated with certain tax matters related to periods prior to December 31, 2025 and other specified tax exposures of SI Partners and its subsidiaries
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▪ the estimated fair value of contingent consideration based on the Ventika wind power generation facilities’ performance through 2028, which could be affected by recent changes to Mexico’s transmission rate methodology applicable to legacy generation facilities
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▪ any difference between actual and projected capital expenditures associated with the ECA LNG Phase 1 project under construction
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Additionally, Sempra expects to recognize additional costs associated with the transaction, including:
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▪ provisions for expected credit losses on the abovementioned notes receivable and related to a previously existing note receivable
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▪ a reimbursement to ADIA in connection with ADIA’s original purchase from Sempra of a 10% interest in SI Partners, which was renegotiated as a result of this transaction and arises from certain project-related conditions not being satisfied within specified timeframes
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(1) In September 2026, SI Partners and IEnova amended their shared credit facility to extend the expiration date from September 2026 to September 2027 and decrease the borrowing capacity from $ 500 to $ 300.
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WEIGHTED-AVERAGE INTEREST RATES September 30, 2026 December 31, 2025 Sempra 4.51% 4.32% SDG&E 4.09 3.96 SoCalGas 4.04 4.17
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FOREIGN CURRENCY DERIVATIVES (Dollars in millions) September 30, 2026 December 31, 2025 Notional amount Maturities Notional amount Maturities Sempra: Cash flow hedges $ 41 2026-2027 $ 172 2026-2027 Undesignated derivatives 100 2027-2028 — —
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In September 2025, PA2 JVCo issued 49.9 % of its equity interests to Blackstone, which we discuss in Note 12 of the Notes to Consolidated Financial Statements in the Annual Report. Upon closing the equity subscription, we received proceeds of $ 106 million and recorded an increase of $ 76 million in CRNCI, an increase of $ 9 million in NCI, and an increase of $ 16 million, net of $ 5 million in income tax expense, in Sempra’s shareholders’ equity. Additionally at closing, Blackstone paid its initial contribution and we received $ 3,166 million in cash, net of $ 168 million in transaction costs, and recorded an increase of $ 3,166 million in CRNCI.
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In September 2025, Sempra provided notice of the redemption of all 900,000 issued and outstanding shares of its series C preferred stock for a redemption price of $ 1,000 per share totaling $ 900 million. Upon notice of the redemption, Sempra recognized $ 11 million of capitalized underwriting discount and equity issuance costs in Preferred Deemed Dividends and $ 4 million of accrued dividends in Interest Expense on Sempra’s Condensed Consolidated Statement of Operations.
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In February 2026, Sempra filed restated articles of incorporation that implemented the revocation of the series C preferred stock, such that the number of authorized shares of such series decreased to zero and it is no longer an authorized series of Sempra’s capital stock.
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In August 2026, SoCalGas held a special shareholders meeting at which its shareholders approved the restated articles of incorporation providing for the retirement of SoCalGas’ outstanding preferred stock. Holders of SoCalGas preferred stock received $ 31.00 in cash per share, representing the $ 25.00 par value plus a $ 6.00 premium, together with accrued and unpaid dividends, for an aggregate payment of $ 27 million. Upon retirement of the preferred stock, SoCalGas recognized the $ 5 million premium paid to preferred shareholders and $ 1 million in retirement costs in Preferred Deemed Dividends on the SoCalGas Condensed Statements of Operations for the three months and nine months ended September 30, 2026.
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At Sempra, the preferred stock at SoCalGas is presented as NCI, except for the preferred stock held by Pacific Enterprises, a wholly owned subsidiary of Sempra. As a result of the retirement, Sempra reduced equity attributable to NCI by $ 20 million and recognized the $ 5 million premium paid to SoCalGas’ preferred shareholders, excluding Pacific Enterprises’ share, and $ 1 million in retirement costs as Preferred Deemed Dividends of Subsidiary on the Sempra Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2026.
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Pending. On October 19, 2026, a lawsuit was filed in Orange County Superior Court against SDG&E, Enova Corporation and Sempra relating to the October 16, 2026 Norte fire near San Clemente, California. The complaint alleges that SDG&E’s electrical facilities caused the fire and asserts claims for negligence, inverse condemnation, premises liability, trespass, private and public nuisance, and violations of the California Public Utilities Code and Health and Safety Code. The lawsuit seeks an award of economic and noneconomic damages, punitive damages, attorney’s fees and litigation costs arising from the fire. The cause of the fire remains under investigation by the Orange County Fire Authority.
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In August 2026, all claims in the lawsuits have been settled in principle, subject to execution of definitive settlement agreements and court approvals, as applicable. Through the settlement process, the pleadings in the lawsuits were amended to assert claims on behalf of 26 total plaintiffs to ensure full and complete dismissals of all claims arising out of or related to the incident. As of November 2, 2026, the claims of 10 plaintiffs have been fully resolved and dismissed.
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▪ $29 million lower income tax benefits primarily from flow-through items, including impacts from the election in 2025 to accelerate self-developed software deductions
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▪ $97 million gain on the sale of Ecogas in August 2026, excluding the effects of foreign currency hedges
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▪ $26 million unfavorable impact in 2025 related to a customer’s early termination of firm transportation agreements, impacting revenue and interest expense
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▪ $97 million gain on the sale of Ecogas in August 2026, excluding the effects of foreign currency hedges
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▪ $26 million unfavorable impact in 2025 related to a customer’s early termination of firm transportation agreements, impacting revenue and interest expense
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▪ $30 million unfavorable impact in 2025 related to a customer’s early termination of firm transportation agreements
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▪ $30 million unfavorable impact in 2025 related to a customer’s early termination of firm transportation agreements
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As we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements, Sempra California recorded a charge in the third quarter of 2026 from regulatory disallowances, net, of $205 million ($151 million after tax), of which $202 million ($149 million after tax) relates to prior years and $3 million ($2 million after tax) relates to 2026.
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In September 2026, Sempra California recognized a $16 million gain on the sale of land, of which $11 million is refundable to ratepayers and offset in natural gas revenues.
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◦ $22 million losses from the settlement of contingent foreign currency hedges associated with the sale of Ecogas in August 2026
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◦ $22 million losses from the settlement of contingent foreign currency hedges associated with the sale of Ecogas in August 2026
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◦ $16 million interest expense in 2025 related to a customer’s early termination of firm transportation agreements
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◦ $16 million interest expense in 2025 related to a customer’s early termination of firm transportation agreements
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◦ $153 million income tax expense in 2025 for changes in state income tax apportionment
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▪ lower income tax benefit from flow-through items, including lower income tax benefits from the election in 2025 to accelerate self-developed software deductions
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◦ $153 million income tax expense in 2025 for changes in state income tax apportionment
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▪ lower income tax benefit from flow-through items, including lower income tax benefits from the election in 2025 to accelerate self-developed software deductions
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▪ a gain on the sale of Ecogas in August 2026, excluding the effects of foreign currency hedges
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▪ $29 million lower income tax benefits primarily from flow-through items, including impacts from the election in 2025 to accelerate self-developed software deductions
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As we discuss in Note 4 of the Notes to Condensed Financial Statements, SDG&E recorded a credit in the third quarter of 2026 from regulatory disallowances, net, of $104 million ($72 million after tax), of which $98 million ($67 million after tax) relates to prior years and $6 million ($5 million after tax) relates to 2026.
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▪ lower income tax benefit from flow-through items, including lower income tax benefits from the election in 2025 to accelerate self-developed software deductions
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As we discuss in Note 4 of the Notes to Condensed Financial Statements, SoCalGas recorded a charge in the third quarter of 2026 from regulatory disallowances of $309 million ($223 million after tax), of which $300 million ($216 million after tax) relates to prior years and $9 million ($7 million after tax) relates to 2026.
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In September 2026, SoCalGas recognized a $16 million gain on the sale of land, of which $11 million is refundable to ratepayers and offset in natural gas revenues.
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▪ lower income tax benefit from flow-through items, including lower income tax benefits from the election in 2025 to accelerate self-developed software deductions
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Separately, SDG&E and SoCalGas submitted a combined Track 3 request seeking review and recovery of $240 million and $499 million, respectively, of PSEP costs. In September 2026, the CPUC issued a PD authorizing revenue requirements through 2026 of $210 million for SDG&E and $361 million for SoCalGas. SDG&E and SoCalGas expect the CPUC to issue an FD in the fourth quarter of 2026.
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As a result of these PDs in the Track 3 requests, SDG&E recorded a credit in the third quarter of 2026 to Regulatory Disallowances, Net, of $104 million ($72 million after tax), of which $98 million ($67 million after tax) relates to prior years and $6 million ($5 million after tax) relates to 2026. The credit consists of the reversal of a portion of the $651 million ($464 million after tax) regulatory disallowance charge recognized in the fourth quarter of 2025, partially offset by an additional regulatory disallowance charge recognized in the third quarter of 2026. SoCalGas recorded a charge in the third quarter of 2026 to Regulatory Disallowances of $217 million ($157 million after tax), of which $209 million ($150 million after tax) relates to prior years and $8 million ($7 million after tax) relates to 2026.
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Field, generation, and call center employees at SDG&E are represented by the International Brotherhood of Electrical Workers Local 465. The collective bargaining agreements for these employees covering wages, hours, working conditions, and medical and other benefit plans were due to expire on August 31, 2026. An agreement to extend all three collective bargaining agreements was ratified on May 13, 2026, and the agreements now expire on August 31, 2029.
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In September 2026, the CPUC issued a PD authorizing an $82 million revenue requirement, compared with the $174 million requested by SoCalGas, for costs associated with the 2019 GRC cycle for integrity assessments and repairs associated with federal regulatory changes. In the third quarter of 2026, SoCalGas recorded a charge of $92 million ($66 million after tax) in Regulatory Disallowances, Net, on the Condensed Consolidated Statements of Operations, of which $91 million ($66 million after tax) relates to prior years and $1 million relates to 2026.
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On October 29, 2026, the CPUC approved a revised PD that reduces the disallowance of capital and O&M costs by approximately $30 million, and allows SoCalGas to propose an alternative allocation of the disallowance between capital and O&M costs. SoCalGas is required to submit an advice letter within 30 days of the FD’s effective date to calculate the final revenue requirement. As a result, the charge SoCalGas recorded in the third quarter of 2026, pursuant to the PD, may change based on the approved advice letter. SoCalGas expects to file the advice letter in the fourth quarter of 2026.
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ERCOT also has implemented a PUCT-approved, system-wide approach to sequence large load customer interconnection requests in a recurring batch interconnection framework, the first stage of which is known as the batch zero process. In August 2026, the Governor of Texas directed the PUCT and ERCOT to conduct a comprehensive verification and audit of all data centers advancing through ERCOT’s interconnection process before allowing any data center project to move forward. In September 2026, ERCOT conditionally released customer load classifications to transmission service providers in the batch zero process that remain subject to completion of ERCOT’s comprehensive audit and additional ERCOT processes. Oncor expects to receive a final transmission plan reflecting the results of ERCOT’s batch zero process in the second half of 2027.
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In July 2026, Sharyland Utilities filed an application with the PUCT for an interim rate adjustment to reflect changes in transmission-related invested capital. Sharyland Utilities requested an increase of approximately $7 million in its revenue requirement, resulting in a total revenue requirement of approximately $59 million. In September 2026, the PUCT approved the total revenue requirement as requested on an interim basis, effective September 10, 2026. The interim rates are subject to reconciliation in Sharyland Utilities’ next rate case.
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Sempra expects to record a gain on the sale upon closing of approximately $2.80 billion to $3.30 billion ($2.00 billion to $2.40 billion after tax), subject to post-closing adjustments, primarily based on:
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▪ the purchase price, subject to adjustments at closing, including (i) adjustments to reflect SI Partners’ net debt, net working capital and capital expenditures as of or through December 31, 2025; (ii) adjustments for certain capital contributions by and distributions to Sempra in 2026 before closing; (iii) costs related to transaction consents; (iv) a ticking fee of 0.625% per month on the aggregate base purchase price that accrues daily beginning April 1, 2026; (v) $338 million of transaction fees reimbursed by Sempra to the KKR Partners; and (vi) other transaction costs
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▪ the estimated fair value of Sempra’s retained 25% equity interest in SI Partners
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▪ estimated carrying values of SI Partners’ net assets, CRNCI, AOCI, NCI, and interest capitalized at Parent and other as of the closing date
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▪ a $340 million credit payable by Sempra for the KKR Partners’ share of development costs through 2027
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▪ the estimated fair value of Sempra’s indemnification obligations to the KKR Partners for potential losses associated with certain tax matters related to periods prior to December 31, 2025 and other specified tax exposures of SI Partners and its subsidiaries
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▪ the estimated fair value of contingent consideration based on the Ventika wind power generation facilities’ performance through 2028, which could be affected by recent changes to Mexico’s transmission rate methodology applicable to legacy generation facilities
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▪ any difference between actual and projected capital expenditures associated with the ECA LNG Phase 1 project under construction
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Additionally, Sempra expects to recognize approximately $450 million to $550 million ($325 million to $400 million after tax) for additional costs associated with the transaction, including:
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▪ provisions for expected credit losses on the abovementioned notes receivable and related to a previously existing note receivable
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▪ a reimbursement to ADIA in connection with ADIA’s original purchase from Sempra of a 10% interest in SI Partners, which was renegotiated as a result of this transaction and arises from certain project-related conditions not being satisfied within specified timeframes
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These estimates are preliminary and based on information available as of the date of this report. The actual gain and costs associated with the transaction could differ, potentially materially, from these estimates.
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In September 2026, Sempra Infrastructure entered into a definitive, 20-year SPA with Petrobras, a Brazilian energy company, for the offtake of 0.8 Mtpa of LNG from the PA LNG Phase 2 project.
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Settlement of contingent foreign currency hedges associated with the sale of (22)
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(Higher) lower payments on short-term debt with maturities greater than 90 days (1,284) 300
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Oncor expects to announce a base capital expenditures plan for the years 2027 through 2031 in the first quarter of 2027 and currently expects that capital expenditures plan to be approximately 20% higher than Oncor’s 2026 through 2030 base capital expenditures plan of $47.5 billion. Oncor also anticipates significant potential capital expenditure opportunities incremental to the 2027 through 2031 base capital expenditures plan. Changes in Oncor’s capital expenditures plan could result in corresponding changes to our projected capital expenditures for PP&E and investments based on our ownership interest in Oncor.
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In the third quarter of 2026, SoCalGas launched a new customer information system (CIS). As a result, SoCalGas modified certain business processes and related internal control over financial reporting associated with billing, revenue and related financial reporting activities. Prior to launching, SoCalGas performed planning, design, development and testing of internal controls and conducted training related to internal controls that became effective in the third quarter of 2026. SoCalGas continues to monitor and enhance these controls as part of the post-implementation process.
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* Portions of the exhibit have been omitted in accordance with applicable SEC rules.
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Item 1A of the 10-Q filed Nov 5, 2026 against Item 1A of the 10-K filed Feb 26, 2026.
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