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YoY shift: Neutral
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.09pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.09pp
Flat
Net-tone change vs last year's 10-K.
MD&A
-0.10pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
closing+8
adverse+6
adversely+4
penalties+4
delays+4
Positive rising
favorable+2
achieved+2
satisfactory+1
successfully+1
positive+1
Risk Factors (Item 1A)
22,371 words
ITEM 1A. RISK FACTORS
When evaluating our company and its businesses and any investment in our or their securities, you should carefully consider the following risk factors and all other information contained in this report and the other documents we file with the SEC (including those filed subsequent to this report). We also may be materially harmed by risks and uncertainties not currently known to us or that we currently consider immaterial. If any of these risks occur, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, our actual results could differ materially from those expressed or implied in our forward-looking statements, and the trading prices of our securities and those of our businesses could decline. These risk factors are not prioritized in order of importance or materiality, and they should be read together with the other information in this report, including in the Consolidated Financial Statements and in “Part II – Item 7. MD&A.”
RISKS RELATED TO SEMPRA
Operational and Structural Risks
Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments.
We are a holding company and substantially all the assets that produce our earnings are owned by our subsidiaries or equity method investees, which are entities we do not control. SI Partners, which primarily constitutes our Sempra Infrastructure reportable segment, will be accounted for as an equity method investment subject to the planned sale of 45% of our equity interest, which we expect to occur in the second or third quarter of 2026. Our ability to pay dividends and meet our debt and other obligations largely depends on distributions from our subsidiaries and equity method investees, which in turn depend on their ability to execute their business strategies and generate cash flows in excess of their own expenditures, dividend payments to third-party owners (if any) and debt and other obligations. In addition, our subsidiaries and entities accounted for as equity method investments are all separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be from doing so by legislation, regulation or contractual restrictions, in times of financial or in other circumstances. Any to access capital from our subsidiaries and equity method investees could have a material effect on our results of operations, financial condition, cash flows and/or prospects.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
closing+30
claims+11
disallowances+10
disallowed+10
termination+7
Positive rising
benefit+7
achieved+6
satisfaction+3
satisfying+3
positive+2
MD&A (Item 7)
64,093 words
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Sempra’s rights to the assets of its subsidiaries and equity method investees are structurally subordinated to the claims of each entity’s trade and other creditors. When Sempra is a creditor of any such entity, its rights as a creditor are effectively subordinated to any security interest in the entity’s assets and any indebtedness of the entity senior to that held by Sempra. In addition, Sempra may elect to make additional capital contributions to its subsidiaries or equity method investments, which are not required to be repaid and are structurally subordinated to claims by creditors of the applicable subsidiary.
Our investments in businesses we do not control expose us to risks.
We have investments in businesses we do not control or manage or in which we share control, including Oncor and SI Partners (subject to closing our planned sale of a portion of our equity interest in SI Partners). We discuss these investments in Note 5 of the Notes to Consolidated Financial Statements. In some cases, we engage in arrangements with or for these businesses that could expose us to risks in addition to our investment, including guarantees, indemnities and loans. For businesses we do not control, we are subject to the decisions of others, which may be adverse to our interests. When we share control of a business with other owners, any disagreements among the owners about strategy, financial, operational, transactional or other important matters could hinder the business from moving forward with key initiatives or taking other actions and could negatively affect the relationships among the owners and the efficient functioning of the business. In addition, irrespective of whether we control these businesses, we would be responsible for certain liabilities or losses related to these businesses, may be subject to disproportional funding obligations for certain matters or priority distributions in favor of other partners or members, and may be required or elect to make additional capital contributions to these businesses. Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
2025 Form 10-K | 40
Tab le of Cont ents
Our business could be negatively affected by activist shareholders.
We have been and may in the future be subject to activist shareholder attention, including proxy solicitations, shareholder proposals or other attempts to effect changes in or assert influence on our board of directors and management. In connection with these efforts, activist shareholders could seek to acquire our capital stock, despite the provisions of our governing documents that may delay, deter or prevent a change of control or other takeover of our company even if our shareholders might prefer such a change of control. At certain ownership levels, these common stock acquisitions could threaten our ability to use some or all of our NOL or tax credit carryforwards if our corporation experiences an “ownership change” under applicable tax rules. Responding to activist shareholders can be costly and time-consuming and requires time and attention from our board of directors and management, diverting their attention from our business strategies.
Any actual or perceived instability in our future direction, inability to execute our strategies, or changes in our board of directors or management team arising from activist shareholder campaigns could be exploited by our competitors and/or other activist shareholders, result in the loss of business opportunities, and make it more difficult to pursue our strategic initiatives or attract and retain qualified personnel and business partners, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Financial and Capital Stock-Related Risks
Successfully executing our five-year capital expenditures plan is subject to risks.
The execution of our five-year capital expenditures plan may not be completed in accordance with current expectations or produce the desired results. Factors that have historically impacted and could continue to impact the amount, timing and types of capital expenditures we make include the cost and availability of financing; economic and market conditions; regulatory decisions; changes in tax law; business opportunities providing desirable rates of return; forecasts related to safety, reliability and load growth, gas system planning and transportation electrification; safety and environmental requirements and climate-related policies; and cooperation of third parties, including customers, partners, suppliers, lenders and others. We discuss these and other relevant factors with respect to each of our businesses below. We aim to finance our five-year capital expenditures plan in a manner that will maintain our investment-grade credit ratings and capital structure, but we may not be able to do so. Any failure to successfully execute our capital expenditures plan could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Settlement provisions contained in forward sale agreements in connection with our ATM program subject us to certain risks.
In November 2024, Sempra established an ATM program, which we discuss in Note 13 of the Notes to Consolidated Financial Statements. We are permitted to sell shares of our common stock in the ATM program pursuant to forward sale agreements, including 4,996,591 shares under existing forward sale agreements that remain subject to future settlement as of February 26, 2026. These forward sale agreements grant each counterparty (forward purchaser) the right to accelerate its forward sale agreement (or, in certain cases, the portion affected by the relevant event) and require us to physically settle the forward sale agreement upon the occurrence of certain events, some of which are not within our control.
A forward purchaser’s decision to exercise this right and require us to physically settle the relevant shares will be made irrespective of our interests, including our capital and other needs. In such cases, we could be required to issue and deliver shares of our common stock under the terms of the physical settlement, which would result in dilution to our EPS and may adversely affect the market price of our common stock and any series of preferred stock we may issue in the future.
The forward price that we expect to receive upon physical settlement of a forward sale agreement will be subject to adjustment on a daily basis based on a floating interest rate factor. If the specified daily rate is less than the applicable spread on any day, this will result in a daily reduction of the forward price. In addition, the forward price will be subject to decrease on certain dates specified in the relevant forward sale agreement by the amount per share of quarterly dividends we expect to declare on our common stock during the term of such forward sale agreement.
We generally have the right, in lieu of physical settlement of any forward sale agreement, to elect cash or net share settlement in respect of any or all of the shares of our common stock subject to each forward sale agreement. If we elect to cash or net share settle all or any part of any forward sale agreement, we would expect to issue a substantially lower number of shares than if we settled by physical delivery, but would not receive the cash for the shares that would have otherwise been issued if we settled the entire forward sale agreement by physical delivery and, as a result, would not derive the same liquidity or credit metrics benefits.
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Tab le of Cont ents
If the price of our common stock at which purchases are made by a forward purchaser (or its affiliate) exceeds the applicable forward price, we will pay the forward purchaser an amount in cash equal to such difference (if we elect to cash settle) or we will deliver to the forward purchaser a number of shares of our common stock having a market value equal to such difference (if we elect to net share settle). Any such difference could be significant and could require us to pay a significant amount of cash or deliver a significant number of shares of our common stock to a forward purchaser.
The purchase of shares of our common stock by a forward purchaser (or its affiliate) to unwind the forward purchaser’s hedge position could cause the price of our common stock to increase above the price that would have prevailed in the absence of those purchases (or prevent a decrease in such price), thereby increasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that we would owe the forward purchaser upon settlement of the applicable forward sale agreement or decreasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that the forward purchaser would owe us upon settlement of the applicable forward sale agreement.
The economic interest, voting rights and market value of our outstanding common stock may be adversely affected by any additional equity securities we may issue.
At February 19, 2026, we had 653,284,140 shares of our common stock outstanding. Our businesses have substantial capital needs, and we may seek to raise capital by issuing additional equity, including in our ATM program, or convertible debt securities in potentially significant amounts depending in part on the prevailing market price of our common stock, which at times experiences substantial volatility. Any future issuance of equity or convertible debt securities may materially dilute the voting rights and economic interests of holders of our outstanding common stock and materially adversely affect the trading price of our common stock.
RISKS RELATED TO ALL SEMPRA BUSINESSES
Operational Risks
Our infrastructure and its supporting systems subject us to risks.
Our facilities and the systems that interconnect and/or manage them are subject to risks of, among other things:
▪ equipment or process failures due to aging infrastructure or otherwise
▪ human error
▪ loss or outage of a key technology platform or system
▪ 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
▪ performance below expected levels
Our businesses undertake capital investment projects to construct, replace, operate, maintain and upgrade facilities and systems, but such projects may not be completed or effective at managing these risks and involve significant costs that may not be recoverable in a timely manner or at all. We often rely on third parties, including contractors, to perform work related to these projects and other activities, which may subject us to liability for safety issues or lower standards of work quality. Because some of our facilities are interconnected with those of third parties, including customer-side-of-meter facilities, natural gas pipelines and power generation facilities, the operation of our facilities could also be materially adversely affected by these or similar risks to such third-party systems, which may be unanticipated or uncontrollable by us.
2025 Form 10-K | 42
Tab le of Cont ents
Additional risks associated with our facilities and systems, which may be beyond our control, include:
▪ failure to meet customer demand for electricity and/or natural gas, including electric or gas outages
▪ gas surges into homes or other properties
▪ release of hazardous or toxic substances, including gas leaks
▪ public contact with energized equipment
▪ worksite accidents and other incidents impacting the health, safety or security of employees, contractors, the public or our infrastructure
▪ failure to respond effectively to catastrophic events
▪ severe weather, which we discuss further in the following risk factor
The occurrence of any of these events could affect supply and demand for electricity, natural gas or other forms of energy, cause unplannedoutages, damage our assets and/or operations or those of third parties on which our businesses rely, damage property owned by customers or others, and cause personal injury or death, such as recent contractor fatalities on certain Sempra Infrastructure projects under construction. In addition, if we are unable to defend and retain title to the properties we own or obtain or retain rights to construct and operate on the properties we do not own in a timely manner, on reasonable terms or at all, we could lose our rights to occupy and use these properties and related facilities, which could prevent, limit or delay existing or proposed operations or projects, increase our costs, and result in breaches of permits or contracts and related impairments, fines or penalties. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We face risks related to severe weather, natural disasters, physical attacks and other similar events.
Our employees and contractors may be harmed and our facilities and infrastructure may be damaged as a result of physical risks, such as extreme temperatures, storms, droughts and other severe weather; natural disasters, including wildfires, land movement, earthquakes, and solar flares; climate-related conditions, including sea level rise and coastal erosion; accidents, including explosions, excavation damage to pipelines and automobile accidents; or acts of terrorism, war or criminality, including physical attacks and unauthorized drone incursions. Because we are in the business of using, storing, transporting and disposing of highly flammable, explosive and radioactive materials and operating highly energized equipment, the risks such incidents pose to our facilities and infrastructure, as well as to the surrounding communities for which we could be liable, are substantially greater than the potential risks to a typical business. Efforts to mitigate these risks could decrease revenues and earnings and/or increase costs, which for our regulated utilities may not be recoverable in rates on a timely basis or at all, including expenditures on infrastructure maintenance and resiliency, physical and employee safety and security, emergency preparedness, wildfire mitigation and grid modernization.
Such incidents, which have occurred from time to time, could result in operational disruptions, electric or gas outages, property damage, personal injury or death and could cause secondary incidents that also may have these or other negative effects, such as fires; leaks or spills of gases, natural gas odorant or radioactive material; damage to natural resources; or other impacts to affected communities. Any of these occurrences could decrease revenues and earnings and/or increase costs, including restoration expenses, amounts associated with claimsagainst us, and regulatory fines, penalties and disallowances. In some cases, we may be liable for damages even though we are not at fault, such as when the doctrine of inverse condemnation applies, which we discuss below under “Risks Related to Sempra California – Operational Risks.” Insurance coverage for these costs may continue to increase or become prohibitively expensive, be disputed by insurers, or become unavailable for certain of these risks or at adequate levels or in certain geographic locations, and any insurance proceeds may be insufficient to cover our losses or liabilities due to limitations, exclusions, high deductibles, failure to comply with procedural requirements or other factors. We discuss the risks related to insurance for wildfire liabilities below under “Risks Related to Sempra California – Operational Risks.” Such incidents that do not directly affect our facilities may impact our business partners, supply chains and transportation and communication channels, which could negatively affect our ability to operate. Moreover, weather-related incidents have become more prevalent, unpredictable and severe due to climate change or other factors. As a result, these incidents could have a greater impact on our businesses than currently anticipated and, for our regulated utilities, rates may not be adequately or timely adjusted to reflect any such increased impact. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
2025 Form 10-K | 43
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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.
Cybersecurity and Technology Resiliency
Our significant reliance on complex technologies and increasing deployment of new technologies, such as advanced forms of automation and artificial intelligence and virtualization of many business activities, represent large-scale opportunities for attacks on or failures of our information systems, the energy grid and our other infrastructure. Our digitalization and grid modernization efforts, including the networking of operational technology assets such as substations, continue to increase the potential vulnerabilities and points of failure in our systems. We are also at risk of attacks on, vulnerabilities in or other failures of technologies and systems used by certain third-party vendors, regulators and/or ISOs, including third-party systems that are integral to our electric utilities’ operations in their respective ISO markets. Viruses, ransomware, malware and other forms of cyber-attacks targeting utility systems and other energy infrastructure continue to increase in sophistication, magnitude and frequency, may not be recognized until launched against a target and may further escalate during periods of heightened geopolitical tensions. Adversaries increasingly use artificial intelligence to develop new hacking tools, exploitvulnerabilities, obscure malicious activities and increase the difficulty of detecting threats. Accordingly, we may be unable to anticipate these techniques or to implement adequate preventative measures, making it impossible to eliminate these risks.
Although we make significant investments in risk management, technology resiliency and cybersecurity measures for the protection of our systems and data, these measures could be insufficient or otherwise fail, particularly against unknown software flaws, insider threats, attacks involving sophisticated adversaries, including nation-state actors, or outages involving key technology vendors and systems. The costs and operational consequences of implementing, maintaining and enhancing these measures are significant and expected to increase to address evolving cyber risks. We increasingly rely on third-party vendors to deploy new technologies and host, maintain and update our systems (including providing security updates), and these third parties may not have adequate risk management, technology resiliency and cybersecurity measures with respect to their systems or may fail to timely provide and install software updates. Certain of our key externally hosted systems depend on global cloud service providers as well as their respective vendors, some of which have experienced significant system failures and outages in the past.
Although we have not experienced a material breach of our information systems or data, we and some of our vendors have been and will likely continue to be subject to breaches of and attempts to gainunauthorized access to our systems or data or efforts to otherwise disrupt our operations. Any actual or perceived noncompliance with applicable legal or regulatory requirements or any incidents impacting our or our vendors’ systems, the integrity of our data or assets or the energy grid could result in disruptions to our business operations; legal or regulatory compliance failures; inability to produce accurate and timely financial statements; energy delivery failures; financial and reputational loss; litigation; and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Although we currently maintain cyber liability insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover the costs associated with a cybersecurity incident, and this insurance may not continue to be available on acceptable terms.
Data Security and Governance
Our businesses collect, process and retain large volumes of data, including personal, sensitive and confidential information from customers, employees, contractors and other third parties. SDG&E and SoCalGas are increasingly required to disclose large amounts of data (including customer personal information and energy use data) to support state energy initiatives, increasing the risks of inadvertent disclosure or unauthorized access of sensitive information. Our businesses operating in California are subject to the California Consumer Privacy Act, which requires companies that collect information about California residents to, among other things, disclose their data collection, use and sharing practices; allow consumers to opt out of certain data sharing with third parties; and assume liability for unauthorized disclosure of certain highly sensitive personal information. Certain of our other businesses may operate in jurisdictions with similar laws.
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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.
We will continue to incur costs related to our deployment of artificial intelligence and compliance with applicable laws and regulations governing data collection, processing and retention. Any actual or perceived noncompliance could result in reputational harm, enforcement actions or other proceedings and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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.
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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.
We actively seek opportunities in the market through acquisitions, partnerships, JVs and divestitures, and we may be unable to complete or realize the anticipated benefits from such transactions.
We diligently analyze the financial viability of acquisitions, divestitures, partnerships and JVs we pursue. However, our diligence may prove to be insufficient and there could be latent or unforeseendefects. In addition, we may not realize the anticipated benefits from future transactions for various reasons, including difficulties integrating or separating operations and personnel effectively or in a timely manner, higher or unexpected transaction or operating costs, unknown liabilities, and fluctuations in markets. We discuss these and other risks related to our planned sale of a portion of our equity interest in SI Partners below under “Risks Related to Sempra Infrastructure – Risks Related to Planned Sales of Certain Assets and Businesses.” Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We face risks related to activities and projects intended to advance new energy-related technologies.
We participate in research, development and demonstration projects and other activities designed to develop and implement new technologies in the energy space, including those related to hydrogen, liquefaction, energy storage, microgrids, carbon sequestration, wildfire mitigation and grid modernization. These activities and projects involve significant employee time, as well as substantial capital resources, and we may be required to impair or write off amounts we have invested if any project is unsuccessful or its book value is less than the amount of our investment. As has happened in the past, regulators may deny rate recovery to our regulated utilities for some of these investments. We have sought and continue to seek a variety of related federal and state funding opportunities for these activities and projects, such as government incentives and subsidies under the IRA, some of which were revised by the OBBBA. These efforts can involve significant compliance requirements and have not always been successful in securing funding on acceptable terms or at all. In addition, the timing to complete these activities and projects is inherently uncertain and may require significantly more resources than we initially anticipate. Moreover, many of these technologies are in the early stage of development and may not prove economically and technically feasible or be accepted by regulators, and the applicable activities and projects may not be completed. If any of these circumstances occur, we may not receive an adequate or any return on our investment, and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
The operation of our facilities depends on good labor relations with our employees and our ability to attract and retain qualified personnel.
Our businesses depend on recruiting, developing and retaining qualified personnel. Several of our businesses have collective bargaining agreements with different labor unions, which are negotiated on a company-by-company basis. At December 31, 2025, employees covered under collective bargaining agreements were 38%, 36% and 56%, respectively, of Sempra’s, SDG&E’s and SoCalGas’ workforce (exclusive of equity method investees), of which the collective bargaining agreements covering 26%, 100% and 0%, respectively, of such employees expire within one year (the SDG&E agreements will expire in August 2026). Any prolonged negotiation or failure to reach an agreement on these labor contracts as they are up for renewal could result in work stoppages or other labor disruptions. Additionally, we have faced a shortage of experienced and qualified personnel in certain specialty operational positions and could experience disruptions from recruiting or retention challenges for personnel in those positions. Any labor disruption, negotiated wage or benefit increases or other challenges, whether due to union activities, employee turnover, labor shortages or otherwise, could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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Our businesses depend on the performance of counterparties.
Our businesses depend on the performance of business partners, customers, suppliers, contractors, and other counterparties under contractual and other arrangements to provide, among other things, services, supplies, equipment or commodities. If they fail to perform their obligations in accordance with these arrangements or elect to exercise early termination rights, we may be unable to meet our obligations and may be required to secure alternative arrangements, if available, or honor our underlying commitments at then-current market prices, which may result in losses or delays or other operational disruptions. Any efforts to enforce the terms of these arrangements through legal or other means could involve significant time and costs and may not succeed. We may not be able to secure replacement agreements on favorable terms, in a timely manner or at all if any of these arrangements terminate. We often face counterparty credit risk with respect to customers, suppliers, and other counterparties and, although we perform credit analyses prior to extending credit or entering into transactions with such counterparties, we may not be able to collect the amounts owed to us. Volatility and disruptions in capital and credit markets could have a negative impact on our counterparties and their ability to meet their obligations. SI Partners also faces risks related to doing business with PEMEX and the CFE, which are Mexican state-owned enterprises, including their financial solvency and performance of their respective contractual obligations. Any delay or default in payment could result in our recording of a provision for expected credit losses on past due receivable balances and lower revenues, as was the case in 2024 and 2025 for a customer at SI Partners. The failure of any of our counterparties to perform their obligations could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Financial Risks
Our debt service obligations expose us to risks.
We have significant debt service obligations and an ongoing need for significant amounts of additional capital, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects by, among other things:
▪ making it more difficult and costly to service, pay or refinance debts as they come due, particularly when interest rates increase or economic or industry conditions are otherwise unfavorable
▪ limiting flexibility to pursue strategic opportunities or react to business developments or industry changes causing lenders to require materially adverse terms for new debt, such as restricting uses of proceeds, imposing liens on our assets and limiting our ability to incur additional debt, pay dividends, repurchase stock, or receive distributions from subsidiaries or equity method investees
The availability and cost of financing could be negatively affected by market and economic conditions and other factors.
Our businesses are capital-intensive, with significant and increasing capital spending expected in future periods. In general, we rely on long-term debt to fund a significant portion of our capital expenditures and to repay or refinance outstanding debt, and we rely on short-term debt to fund a significant portion of day-to-day operations. Certain of our businesses also rely on other funding sources, such as Sempra Infrastructure’s use of capital contributions from its owners and various forms of project financing, which may involve guarantees, indemnities or other arrangements that expose us to additional risks, such as potential losses upon the occurrence of events related to the development, construction, operation or financing of the applicable projects. Sempra has also raised and may continue to seek capital by issuing equity, including in our ATM program, or selling equity interests in our subsidiaries or investments.
External sources of capital may not be adequate or available on reasonable terms, in a timely manner or at all. Limitations on the availability of credit, increases in interest rates or credit spreads due to inflation or otherwise or other negative effects on the terms of any financing we pursue could cause us to fund operations and capital expenditures at a higher cost or fail to raise our targeted amount of funds, which could negatively impact our ability to meet contractual and other commitments, progress development projects, make non-safety related capital expenditures and effectively sustain operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
In addition to market and economic conditions, factors that can affect the availability and cost of capital include:
▪ adverse changes to laws and regulations
▪ for Sempra and SDG&E, risks related to California wildfires
▪ for Sempra, SDG&E and SoCalGas, any deterioration of or uncertainty in the political or regulatory environment for companies operating in California
▪ credit ratings downgrades
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Credit rating agencies may downgrade our credit ratings or place them on negative outlook, and our efforts to maintain these ratings could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects in development.
Credit rating agencies routinely evaluate Sempra, SDG&E, SoCalGas, SI Partners and certain of our other businesses, whose ratings are based on many factors, including, as applicable, the ability to generate cash flows; terms and levels of indebtedness, including the credit rating agencies’ treatment of certain types of indebtedness, such as subordinated indebtedness which is given partial equity credit but carries a higher interest rate than comparable senior indebtedness; overall financial strength; specific transactions or events, such as share repurchases and significant litigation; the status of certain capital projects; and general economic and industry conditions. The Rating Agencies also have specified certain events that could lead to negative ratings actions, including, among others:
▪ weakening of certain financial measures or failure to meet certain financial credit metrics
▪ ratings downgrades at certain affiliated entities
▪ for Sempra, expansion of unregulated businesses in a manner inconsistent with its present level of credit quality
▪ for Sempra and SDG&E, catastrophic wildfires caused by SDG&E or any other California electric IOU that participates in the Wildfire Fund and Continuation Account
▪ for SDG&E and SoCalGas, a deterioration of the legislative or regulatory environment, including credit negative outcomes of regulatory proceedings
▪ for Sempra and SI Partners, the PA LNG Phase 1 project or PA LNG Phase 2 project experiencing higher construction costs, delays or other challenges
In an effort to maintain these credit ratings, we may seek to reduce our outstanding indebtedness or our need for additional indebtedness by reducing or postponing discretionary, non-safety or reliability related capital expenditures or investments in new businesses. We may also issue additional equity securities, including in our ATM program, or sell additional equity interests in our subsidiaries or development projects. We may not be able to complete any such equity sales on acceptable terms or at all, and any new equity issued by Sempra may dilute the voting rights and economic interests of Sempra’s existing equity holders. Any such outcome could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.
Although we aim to maintain or improve these credit ratings, they could be downgraded or subject to other negative rating actions at any time, such as S&P’s January 2025 actions that revised Sempra’s outlook to negative from stable and downgraded SoCalGas’ issuer credit rating, and Moody’s March 2025 action that revised Sempra’s outlook to negative from stable. A downgrade of any of our businesses’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, could materially adversely affect the interest rates at which borrowings can be made and debt securities issued and the various fees on our credit facilities. This could make it more costly to borrow money, issue securities and/or raise other types of capital, any of which could reduce our ability to meet our debt obligations and contractual commitments and, in the case of our regulated utilities, increase customer rates, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We discuss these credit ratings in “Part II – Item 7. MD&A - Capital Resources and Liquidity.”
We do not fully hedge our assets or contract positions against changes in commodity prices or interest rates, and for positions that are hedged, our hedging mechanisms may not mitigate our risk or reduce our losses as intended.
We use forward contracts, futures, financial swaps and/or options, among other mechanisms, to hedge a portion of our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity in an effort to reduce our, and for SDG&E and SoCalGas, customers’ financial exposure related to commodity price fluctuations. In addition, we have used and may continue to use similar financial instruments to hedge against changes in interest rates. The extent to which we hedge our positions varies over time. Certain derivative instruments are recorded at fair value through earnings to reflect movements in the price of the derivative, which has recently and could in the future create volatility in our earnings. The effect of such commodity derivative instruments for SDG&E and SoCalGas are passed through to customers in rates without markup. To the extent we have unhedged positions, if any hedging counterparty fails to fulfill its contractual obligations, or if our hedging strategies do not work as intended, fluctuating commodity prices and interest rates could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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Risk management procedures may not prevent or mitigate losses.
Although we have risk management and control systems designed to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended or function as expected. In addition, daily VaR and loss limits, which are primarily based on historic price movements and which we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” may not protect us from losses if prices significantly or persistentlydeviate from historic prices. As a result of these and other factors, our risk management procedures and systems may not prevent or mitigate losses that could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
An impairment of our long-lived assets could result in a material charge to earnings.
We test long-lived assets, including equity method investments, for recoverability when events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the assets. We could experience events or changes in circumstances from, among other things, (i) an inability to operate our existing facilities; (ii) an inability to collect from customers; (iii) changes to laws or regulations or other circumstances affecting the energy sector or our assets in Mexico; (iv) adverse rulings in lawsuits, binding arbitrations, regulatory proceedings, audits and other proceedings materially impacting our businesses and (v) more generally any loss of permits or approvals that requires us to adjust or cease certain operations and any failure to complete or receive an adequate return on our investments in capital projects. A material charge to earnings from an impairmentloss could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Market performance, significant transactions or changes in other assumptions could require unplanned contributions to pension and PBOP plans.
Sempra, SDG&E and SoCalGas provide defined benefit pension and PBOP plans to eligible employees and retirees. The cost of providing these benefits is affected by many factors, including the market value of plan assets, the partial termination of Sempra’s pension plan in connection with the planned sale of a portion of our equity interest in SI Partners and the other factors described in Note 9 of the Notes to Consolidated Financial Statements and “Part II – Item 7. MD&A – Capital Resources and Liquidity.” A decline in the market value of plan assets or an adverse change in any of these other factors could cause a material increase in our funding obligations for these plans, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Legal and Regulatory Risks
We face risks related to the evolving regulatory environment, including failures or delays in obtaining and maintaining franchises and other required approvals and potential negative impacts of our legislative and regulatory advocacy efforts.
The industries in which we operate are subject to extensive regulation, increasing regulatory uncertainty and political influence and polarization.
Our businesses require numerous permits, licenses, rights-of-way, franchises, certificates and other approvals from federal, state, local and foreign governmental agencies. These approvals may not be granted in a timely manner (including due to potential staffing and funding issues at regulatory agencies) or at all or may be modified, rescinded or fail to be extended for a variety of reasons, including due to legal or regulatory changes or political considerations. The City of San Diego is studying the feasibility of municipalization as a potential alternative to SDG&E’s existing electric franchise agreement, and various aspects of SDG&E’s natural gas and electric franchise agreements have also been challenged in a lawsuit that we discuss in Note 16 of the Notes to Consolidated Financial Statements. At SI Partners, amendments to Mexico’s Constitution and the 2025 Energy Laws have increased government control and participation in the energy sector and may create novel challenges for infrastructure development and operations. Obtaining or maintaining required approvals could result in higher costs or the imposition of conditions or restrictions on our operations. Further, noncompliance by us or certain of our customers with the terms of these approvals could result in their modification, suspension or rescission and subject us to reduced revenue, fines and penalties. If any of these approvals are suspended, rescinded or otherwise terminated or modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise impracticable, we may be required to adjust or temporarily or permanently cease certain of our operations, sell the associated assets or remove them from service and/or construct new assets intended to bypass the impacted area, in which case we may lose some of our rate base or revenue-generating assets, our development and construction projects may be negatively affected and we may incur impairment charges or other costs that may not be recoverable. The occurrence of any of these events could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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From time to time, we invest funds in projects prior to receiving all regulatory approvals. Any inability to recover funds invested in these projects could materially increase our costs, result in material impairments, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We may be unable to recover any or all amounts invested in such projects if:
▪ there is a delay in obtaining these approvals
▪ any approval is conditioned on changes or other requirements that increase costs or impose restrictions on our existing or planned operations
▪ we fail to obtain or maintain these approvals or comply with them or other applicable laws or regulations
▪ we are involved in litigation that adversely impacts any approval or rights to the applicable property or assets
▪ management decides not to proceed with a project
▪ 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.
We face risks related to environmental and climate change regulation and the costs of the energy transition.
The impacts from efforts to mitigate climate change and related regulations may increase the costs we incur to procure and transmit energy and provide other services. The changes in costs and preferences for lower carbon and renewable energy sources may impact the demand for, consumption of, and types of energy we transmit and distribute.
Environmental and Climate Change Regulation
We are subject to extensive federal, state, regional, local, tribal and foreign laws and regulations relating to climate change and environmental protection. To comply with these laws and regulations, we must expend significant capital and employee resources on environmental monitoring, surveillance and other measures to track and disclose performance; acquisition and installation of pollution control equipment; implementation of environmental safety practices; other mitigation efforts; and emissions fees, taxes, penalties and other payments. These requirements could increase as a result of various factors we may not control, including changes to laws and regulations, many of which are becoming more burdensome in light of increasing environmental concerns and related changes to legal and regulatory frameworks; increased readiness and enforcement activities; delays in the renewal and issuance of permits; evolving expectations of investors and other stakeholders; and changes to the mix of energy we transmit and distribute, any of which could negatively impact our operations, costs and corporate planning, demand for our services, customer affordability, and the scope and economics of proposed infrastructure projects or other capital expenditures. In particular, legislation and regulation designed to reduce GHG emissions and mitigate climate change are proliferating, as we discuss in “Part I – Item 1. Environmental Matters.” California’s goals are facing cost pressures and may experience delays or other challenges that could cause the state to modify its laws and rules, resulting in significant uncertainty. Any failure to comply with these or other environmental laws and regulations may subject us to fines and penalties, including criminalpenalties in some cases, and/or curtailment of our operations.
In addition, we are generally responsible for hazardous substances and other contamination on, and the conditions of, our projects and properties, regardless of when these conditions arose and whether they are known or unknown. We have been and may in the future be required to pay environmental remediation costs at former facilities and off-site waste disposal sites where any of our businesses is identified as a PRP under federal, state and local environmental laws. For our regulated utilities, some or all of these costs may not be recoverable in rates.
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Additionally, California laws requiring expansive disclosures on GHG emissions and other environmental measures, targets and claims subject us to potential liability for these disclosures as well as significant compliance costs and could have other consequences that may be difficult to predict, including negative sentiment from current and potential investors, regulators, legislators or other groups. These California disclosure requirements, which remain subject to rulemaking by CARB and have been the subject of legal challenges, and other voluntary disclosures we make may use different reporting frameworks, methodologies and boundaries from each other, which may further increase compliance costs and the risk of compliance failures and may create confusion for stakeholders. Moreover, these disclosure requirements could increase the risk that we become subject to climate change lawsuits. Defense costs associated with such litigation could be significant, and any adverse outcome could require substantial capital expenditures or payment of substantial penalties or damages.
Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Other Energy Transition Risks
The energy transition in California and elsewhere, including decarbonization goals and increasingly divergent investor sentiment regarding climate change efforts, has led to contradictory expectations from various investors and other stakeholders and uncertainty in long-term investor support, including some investors reducing participation in or divesting from our sector. Maintaining investor confidence and attracting capital at a competitive cost will depend, in part, on demonstrating our ability to address material business risks related to climate and our efforts to help achieve the goals of our consumers and the markets and jurisdictions where we operate. In an effort to maintain a sustainable and durable business risk profile and continue to focus on value creation, Sempra updated its climate aspirations to reflect the changing policy, regulatory, commercial and technological landscape, including stakeholders’ evolving focus on reliability, resiliency and affordability and the pace and impact of climate and other public policies. Sempra aims to have net-zero scope 1 and 2 GHG emissions by 2050 and has an interim aim of 50% scope 1 and 2 GHG emissions reductions by 2035 (this interim target is relative to a 2019 baseline, applies to Sempra California’s operations and Sempra Infrastructure’s Mexico (non-LNG) operations, and may be subject to further revision if Sempra’s planned sale of a portion of its equity interest in SI Partners is completed). Sempra’s, SDG&E’s and SoCalGas’ abilities to advance their respective net-zero and other climate objectives and meet the demand for lower-carbon and reliable energy in California and elsewhere will depend on many factors, some of which we do not control, including supportive federal and state energy laws, policies, incentives, tax credits and regulatory decisions; cost and affordability considerations; development, commercialization and regulatory acceptance of affordable, alternative and lower-carbon energy sources, including cleaner fuels; successful research and development efforts focused on lower carbon technologies that are economically and technically feasible; cooperation from our partners, financing sources and commercial counterparties; and consumers’ decisions and preferences. In addition, we will need to continue to expend capital and employee resources to develop and deploy new technologies and modernize grid systems, which may not be recoverable in rates or, with respect to our businesses that are not regulated utilities, may not be able to be passed through to customers. Even if such costs are recoverable, these costs, coupled with necessary safety and reliability investments, may negatively impact the affordability of SDG&E’s and SoCalGas’ services and, for our businesses that are not regulated utilities, may cause costs to increase to levels that reduce customer demand and growth. Moreover, forecasting specified targets over longer-term periods is inherently uncertain and could be significantly impacted by the trajectory of the energy transition. As a result, although we are dedicated to making progress on our climate aims and are continuing to develop capabilities designed to reduce GHG emissions from our own operations as well as to support consumers’ and markets’ climate goals and applicable legislative and regulatory mandates, we may not be successful in achieving these objectives. We could sufferdifficulties attracting investors and business partners, reputational harm and other negative effects if we do not meet or if we further modify our GHG emissions reduction aims or there are negative views about our environmental disclosures or practices generally.
We develop our capital expenditure plans based on assumptions and forecasts as well as regulatory and compliance requirements, including those related to safety, reliability and load growth, gas system planning, and transportation electrification, which generally assume that California will continue to pursue consistent environmental and climate-related policies. If the federal government continues to reduce its support for grid and infrastructure modernization or takes further action to prohibit California from pursuing its environmental and climate-related policies, or if California changes its policies, the assumptions and forecasts underlying our capital expenditure plans may prove to be inaccurate, and our investment plans could suffer significant negative effects.
The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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We are subject to complex tax and accounting requirements that expose us to risks.
We are subject to complex tax and accounting requirements. These requirements may undergo changes at the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these requirements and any changes to them or how they are implemented, interpreted or enforced could increase our operating costs and materially adversely affect how we conduct our business. New tax legislation, such as the OBBBA, and new regulations or interpretations or changes in tax policies in the U.S., Mexico or other countries in which we do business could negatively affect our tax expense and/or tax balances and our businesses generally. Any failure to comply with these requirements could subject us to fines and penalties, including criminalpenalties in some cases. The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We may be negatively impacted by the outcome of litigation or other proceedings in which we are involved.
Our businesses are involved in a number of lawsuits, appeals, binding arbitrations, regulatory investigations and other proceedings. We discuss material pending proceedings in Note 16 of the Notes to Consolidated Financial Statements. Our businesses also may become involved in proceedings that we do not consider material, such as the approximately 28,000 proofs of claim that have been filed on behalf of persons who assert the right to file lawsuits in the future based on alleged exposure to asbestos in power plants designed and/or built by certain predecessor entities we acquired in connection with our acquisition of our majority interest in Oncor. We have spent, and continue to spend, substantial capital and employee resources on lawsuits and other proceedings. The uncertainties inherent in lawsuits and other proceedings and the broad range of potential outcomes make it difficult to estimate with any degree of certainty the timing, costs and other potential impacts of these matters, and changes or disruptions to judicial systems, such as the nationwide strike by the Mexican judiciary in 2024 in response to judicial reforms and the limitations on operations of U.S. federal courts in 2025 due to lapses in congressional appropriations, could result in delays, increased costs, or unfavorable outcomes. In addition, juries have demonstrated a willingness to grant large awards, including punitivedamages, in response to personal injury, product liability, property damage, nuisance, and other claims. Accordingly, actual costs incurred have and may continue to differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, from insurance or in customer rates. Any of the foregoing could cause reputational damage and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
RISKS RELATED TO SEMPRA CALIFORNIA
Operational Risks
Wildfires in California pose risks to Sempra, SDG&E and SoCalGas.
More and Increasingly Severe Wildfires
In recent years, California has experienced some of the largest wildfires (measured by acres burned and/or structures destroyed) in its history. Frequent and severedrought conditions, inconsistent and extreme swings in precipitation, changes in vegetation, unseasonably warm temperatures, low humidity, strong winds and other factors have increased the duration of the wildfire season and the intensity, prevalence and difficulty of preventing and containing wildfires in California, including in SDG&E’s and SoCalGas’ service territories. Changing weather patterns, including as a result of climate change, could exacerbate these conditions. Certain California local land use policies and forestry management practices, as well as expanded construction and development of residential and commercial projects in high-risk fire areas, could lead to increased third-party claims and greaterlosses related to fires for which SDG&E or SoCalGas may be liable.
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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Future wildfires in SDG&E’s or SoCalGas’ service territories could compromise SDG&E’s and SoCalGas’ electric and natural gas infrastructure and result in further service disruptions, which could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects. We discuss these risks further in this risk factor below and above under “Risks Related to All Sempra Businesses – Operational Risks.”
The Wildfire Legislation
In July 2019 and September 2025, respectively, the 2019 Wildfire Legislation and the 2025 Wildfire Legislation (collectively, the Wildfire Legislation) were signed into law, which we discuss in Note 1 of the Notes to Consolidated Financial Statements. The 2019 Wildfire Legislation established the Wildfire Fund and the 2025 Wildfire Legislation established the Continuation Account, which offer liquidity to reimburse wildfire-related claims incurred by participating California electric IOUs in excess of $1 billion, subject to the coverage of each fund. The Wildfire Legislation’s legal standards for the recovery of wildfire costs may not be implemented effectively or applied consistently. Moreover, the Wildfire Fund and the Continuation Account, if it becomes operative, could be materially reduced, exhausted, or terminated due to claims by SDG&E or other participating IOUs related to fires caused by utility conduct or operations, or SDG&E could fail to maintain a valid annual safety certification from the OEIS or meet other requirements, any of which could result in SDG&E losing eligibility for the Wildfire Legislation’s liability cap and the other protections afforded by these funds. As a result, a fire resulting from the conduct or operations of any participating California electric IOU could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects, with potentially material additional exposure if SDG&E’s conduct or operations is determined to be a cause of a fire and SDG&E is found to have acted imprudently.
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.
The Wildfire Legislation did not change the doctrine of inverse condemnation, which imposes strict liability for certain types of claims (meaning that liability is irrespective of negligence or intent) on a utility whose equipment is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including business interruptionlosses, interest and attorneys’ fees, even if the utility is not found negligent. In the past, the CPUC has denied recovery of incurred costs associated with wildfire claimsdespite the doctrine of inverse condemnation, which was historically based on the ability of a utility to pass such costs through to rate payers. The doctrine of inverse condemnation also is not exclusive of other theories of liability, such as negligence, under which additional liabilities, such as fire suppression, clean-up and evacuation costs, medical expenses, and personal injury, punitive and other damages, could be imposed. We are unable to predict the impact of the Wildfire Legislation on SDG&E’s ability to recover costs and expenses if SDG&E’s equipment is determined to be a cause of a fire.
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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Cost Recovery Through Insurance or Rates
As a result of California’s doctrine of inverse condemnation, substantial losses recorded by insurance companies, and increased wildfire risk, obtaining insurance coverage for wildfires potentially associated with SDG&E’s equipment (or, to a lesser extent, SoCalGas’ equipment) has become increasingly difficult and costly. If these conditions continue or worsen, including as a result of the LA Fires, insurance for wildfire liabilities may become unavailable or may become prohibitively expensive and we may be denied recovery of insurance cost increases through the regulatory process. In addition, insurance for wildfire liabilities may not be sufficient to cover all losses we may incur, or it may not be available to meet the $1.0 billion of primary insurance required by the Wildfire Legislation. Wildfire insurance may also become prohibitively expensive or unavailable for homeowners and businesses in SDG&E’s service territory, potentially increasing SDG&E’s financial exposure if a wildfire is found to be caused by SDG&E’s equipment. We may be unable to recover in rates or from the Wildfire Fund or the Continuation Account the amount of any uninsuredlosses (including amounts paid for self-insurance and other costs). A loss that is not fully insured, is not sufficiently covered by the Wildfire Fund or the Continuation Account and/or cannot be recovered in customer rates could materially adversely affect Sempra’s and one or both of SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
Regulatory Actions Related to Wildfire Mitigation Efforts
Although we expend significant resources on measures designed to mitigate wildfire risks, these measures may not be effective in preventing wildfires or reducing our wildfire-related losses, and their costs may not be fully recoverable in rates. SDG&E is required by California law to submit WMPs for approval by the OEIS and could be subject to increased risks if these plans are not approved in a timely manner or SDG&E is determined to not have substantially complied with its approved plans, including the risk of fines or penalties for non-implementation or denial of its safety certification. Moreover, wildfire mitigation investments incremental to those authorized in a GRC may be subject to reasonableness reviews after they are made and could be subject to disallowances as a result of such reviews, as was the case with the FD issued in connection with SDG&E’s Track 2 request in its 2024 GRC. One of SDG&E’s wildfire mitigation strategies is to de-energize certain circuits for safety when there is elevated weather-related wildfire ignition risk. These “public safety power shutoffs” have been subject to scrutiny by various stakeholders, including customers, regulators and lawmakers, which could increase the risk of regulatory fines and penalties, claims for damages and reputational harm if SDG&E is found not to have acted within applicable guidelines and regulations. Such costs may not be recoverable in rates. Unrecoverable costs, adverse legislation or rulemaking, stakeholder scrutiny, ineffective wildfire mitigation measures or other negative effects associated with these efforts could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
The electricity industry is undergoing significant change .
Electric utilities in California are experiencing increasing deployment of solar and wind generation, including DER, energy storage and energy efficiency and demand management technologies, and California’s environmental policy objectives are accelerating the pace and scope of these changes. This growth will require further modernization of the electric grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, attaining California’s clean energy goals will require sustained investments in transmission and distribution grid modernization, renewable energy integration projects, operational and data management systems, and electric vehicle and energy storage infrastructure, which may increase exposure to overall grid instability and technology obsolescence. The growth of third-party energy storage alternatives and other technologies also may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities. The CPUC is conducting various proceedings regarding DER, including the evaluation of special programs and pilot projects; changes to the planning and operation of the electric grid to prepare for higher penetration of DER; future grid modernization investments; the deferral of traditional grid investments by DER; and the role of the electric grid operator. These proceedings and the broader changes in California’s electricity industry could result in new regulations, policies and/or operational changes that could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
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Most of SDG&E’s customers receive electric commodity service from a load-serving entity other than SDG&E through programs such as CCA and DA. CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, as is the case with the City of San Diego and certain other jurisdictions in SDG&E’s service territory, and DA is currently limited by a cap based on gigawatt hours. Due to this departed load, SDG&E’s historical energy procurement commitments for future deliveries exceed the needs of its remaining bundled customers. To help achieve the goal of ratepayer indifference (as to whether customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The framework is intended to more equitably allocate SDG&E’s historical energy procurement cost obligations among customers served by SDG&E and customers now served by CCA and DA. If the framework or other mechanisms designed to achieve ratepayer indifference do not perform as intended, if the law changes, or if the law is not interpreted or enforced as expected, SDG&E’s remaining bundled customers could experience large increases in rates for ongoing historical commodity costs under commitments made on behalf of CCA and DA customers prior to their departure or, if all such costs are not recoverable in rates, SDG&E could experience material increases in its unrecoverable commodity costs. 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.
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.
Natural gas continues to be the subject of political and public debate, including a desire by some to reduce or eliminate reliance on natural gas as an energy source .
Certain California legislators, regulators and other stakeholders have expressed a desire to limit or eliminate reliance on natural gas as an energy source through increased use of renewable electricity and electrification. Reducing methane emissions also has become a major focus of certain local and state agencies, resulting in passed or proposed legislation, regulation, policies and ordinances to prohibit or restrict the use of natural gas in new buildings, appliances and other applications, including proposed and recently enacted requirements regarding space and water heaters in newly constructed buildings and an open CPUC proceeding to establish long-term gas system infrastructure planning for natural gas utilities in alignment with California’s decarbonization goals. Additionally, customer preferences may drive increased disconnections from gas service. These actions could result in reduced natural gas use over time and changes to rate and cost recovery policies, and the combination of reduced load and increasing costs to maintain the gas system could negatively impact affordability for remaining natural gas customers. Moreover, a substantial reduction in or the elimination of natural gas use in California could result in impairment of some or all of SDG&E’s and SoCalGas’ natural gas infrastructure assets without adequate recovery of investments, if they were not permitted to be repurposed, or if they were required to be depreciated on an accelerated basis or were to become stranded, in which case, SDG&E and SoCalGas could be required to incur significant decommissioning or other costs, which may require additional funding and may not be recoverable in rates. For instance, in a prior proceeding that is now closed, the CPUC evaluated the feasibility of minimizing or eliminating SoCalGas’ Aliso Canyon natural gas storage facility. The authorized storage level and reliance on the facility in general remain subject to a biennial administrative staff review by the CPUC and additional CPUC proceedings. A permanent closure, which could only be achieved through a new CPUC proceeding, could result in an impairment of the facility that could be material, and a closure or significant reduction in authorized capacity could risk energy and electric reliability in the region. Any such outcome could have a material adverse effect on Sempra’s, SoCalGas’ and SDG&E’s results of operations, financial conditions, cash flows and/or prospects.
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SDG&E may incur significant costs and liabilities from its partial ownership of a nuclear facility being decommissioned .
SDG&E has a 20% ownership interest in SONGS, which we discuss in Note 15 of the Notes to Consolidated Financial Statements. SDG&E is responsible for financing its proportionate share of the facility’s expenses and capital expenditures, including those related to decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to risks, including:
▪ the potential release of radioactive material
▪ the potential harmful effects from the former operation of the facility
▪ limitations on the insurance commercially available to cover losses associated with operating and decommissioning the facility
▪ uncertainties with respect to the technological, financial, and political aspects of decommissioning the facility and the long-term storage of radioactive materials
SDG&E maintains the SONGS NDT to provide funds for nuclear decommissioning. Trust assets generally have been invested in equity and debt securities, which are subject to market fluctuations. A decline in the market value of trust assets, an adverse change in the law regarding funding requirements for decommissioning trusts, or changes in assumptions or forecasts related to decommissioning timing and costs could increase the funding requirements for these trusts, which costs may not be fully recoverable in rates. In addition, CPUC approval is required to make withdrawals from the NDT, which may be denied if the expenditures are found to be unreasonable. In addition, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the NDT. Rate recovery for overruns would require CPUC approval, which may be denied.
The occurrence of any of these events could result in a reduction in our expected recovery and have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
Legal and Regulatory Risks
SDG&E and SoCalGas are subject to extensive regulation.
Rates and Other Financial Matters
The CPUC regulates SDG&E’s and SoCalGas’ customer rates and conditions of service, except for SDG&E’s interstate electric transmission and wholesale electric rates and conditions of service, which are regulated by the FERC. The CPUC also regulates SDG&E’s and SoCalGas’ sales of securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters in various ratemaking proceedings. The CPUC periodically approves SDG&E’s and SoCalGas’ customer rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments while incorporating a risk-based decision-making framework, as well as certain settlements with third parties and mandatory social programs. The timing and outcome of ratemaking proceedings can be affected by various factors, many of which are not in our control, including the level of opposition by intervening parties; any rejection by the CPUC of settlements with third parties; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of regulators, customers and other stakeholders. These ratemaking proceedings include decisions about major programs in which SDG&E and SoCalGas make investments under an approved CPUC framework, such as wildfire mitigation, pipeline and storage integrity and safety enhancement programs, but which investments may remain subject to CPUC filings or reasonableness reviews that may result in the disallowance of incurred costs, as was the case with SDG&E’s Track 2 request in its 2024 GRC. SDG&E and SoCalGas also may be required to make investments and incur other costs before they can request rate recovery for certain projects or to comply with proposed legislative and regulatory requirements, including those related to California’s climate goals and policies, before finalization of the requirements and corresponding ratemaking mechanisms, which investments may not ultimately be fully recoverable. Recovery may be delayed and/or insufficient if ratemaking mechanisms involve a significant time lag between when costs are incurred and when those costs are recovered in rates or if there are material differences between the authorized costs embedded in rates (which are set on a prospective basis) and the actual costs incurred. As was the case with respect to the 2024 GRC FD, delays may also result from the regulatory process and the CPUC may deny recovery altogether on the basis that costs were not reasonably or prudently incurred or for other reasons, such as customer affordability. Even if recoverable, simultaneously investing in support of necessary safety and reliability and regulatory requirements and demand for reliable lower-carbon energy may negatively impact the affordability of SDG&E’s and SoCalGas’ services and their and Sempra’s results of operations, financial condition, cash flows and/or prospects.
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A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and return on rate base. The CPUC applies the CCM, which we describe in “Part I – Item 1. Business – Ratemaking Mechanisms” and Note 4 of the Notes to Consolidated Financial Statements, in the interim years to consider changes in the cost of capital using changes in interest rates. Any rate changes due to a downward trigger of the CCM, the denial by the CPUC of an automatic upward trigger of the CCM or further structural changes to the CCM could have a material adverse effect on Sempra’s and the applicable utility’s results of operations, financial condition, cash flows and/or prospects. We discuss the CCM in “Part I – Item 1. Business – Ratemaking Mechanisms – Sempra California – Cost of Capital Proceedings,” and in Note 4 of the Notes to Consolidated Financial Statements.
The FERC regulates electric transmission rates, transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return and rates of depreciation on electric transmission investments, and other similar matters involving SDG&E. These ratemaking mechanisms are subject to many risks similar to those described above regarding CPUC ratemaking proceedings. In particular, SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision had been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019. In October 2024, SDG&E submitted its TO6 filing to the FERC and requested it to be effective January 1, 2025. SDG&E’s TO6 filing proposed, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing, subject to refund; suspended the effective date to June 1, 2025; established hearing and settlement judge procedures; and disallowed the inclusion of the California ISO adder, the last of which SDG&E has appealed. In February 2026, the settlement judge in the TO6 proceeding reported to the FERC that the participants had reached an agreement in principle on all issues in the proceeding. The parties will draft an offer of settlement to be filed with the FERC for approval. Any unfavorable outcome in these proceedings, such as an authorized ROE that is materially lower than the requested ROE, could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
Operational Matters
Our operations are subject to CPUC rules (and similar FERC rules), commonly referred to as “affiliate rules,” relating to transactions among SDG&E, SoCalGas and other Sempra businesses. These rules primarily impact market transactions and marketing activities involving transmission supply and capacity, including sales or other trades of natural gas or electricity within or among SDG&E and SoCalGas and Sempra and its covered affiliates. Noncompliance with these rules, as well as any changes or additions to these rules or their interpretations, could materially adversely affect our operations and, in turn, our results of operations, financial condition, cash flows and/or prospects.
Additionally, the CPUC has regulatory authority related to safety standards and practices, reliability and planning, competitive conditions and a wide range of other operational matters, including restrictions on funding of lobbying or other political activities, promotional advertising and certain other costs, as well as citation and enforcement programs concerning matters such as safety activity, disconnection and billing practices, commodity pricing, resource adequacy and environmental compliance. Many of these standards and citation and enforcement programs are becoming more stringent and could subject a utility to significant penalties and fines, as well as higher operating costs. The CPUC conducts reviews and audits of the matters under its authority and may launch investigations or open proceedings at its discretion, the results of which could include citations, disallowances, fines and penalties, as well as requirements for corrective or mitigation actions to address any noncompliance, any of which may not be sufficiently funded by customer rates or at all. Any such occurrence could result in other regulatory exposure, significant litigation, and reputational harm and could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
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.
We discuss various CPUC and FERC proceedings relating to SDG&E and SoCalGas in Note 4 of the Notes to Consolidated Financial Statements.
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Regulatory and Legislative Changes and Influence of Other Organizations
SDG&E and SoCalGas incur significant capital, operating and other costs associated with regulatory compliance. Sempra, SDG&E and SoCalGas may be materially adversely affected by revisions or reinterpretations of existing or new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies, any of which could change how SDG&E and SoCalGas operate, affect their ability to recover various costs through rates or adjustment mechanisms, require them to incur additional compliance or other costs, including fines and penalties, or otherwise materially adversely affect their and Sempra’s results of operations, financial condition, cash flows and/or prospects.
SDG&E and SoCalGas are also affected by numerous advocacy groups, including California Public Advocates Office, The Utility Reform Network, Utility Consumers’ Action Network and the Sierra Club. Success by any of these groups in directly or indirectly influencing legislators and regulators could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
Failure by the CPUC to adequately reform SDG&E’s electric rate structure could negatively impact Sempra and SDG&E.
The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable energy generation (primarily solar) for residential and business customers. Depending on when the on-site generation is installed, NEM customers receive a full retail rate or a reduced retail rate for energy they generate but do not use that is fed to the utility’s power grid, which results in these customers not paying their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain exceptions, but still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. As more and higher electric-use customers switch to NEM and self-generate energy, the burden on remaining non-NEM customers, who effectively subsidize the unpaid NEM costs, increases, which in turn encourages more self-generation and further increases rate pressure on remaining non-NEM customers.
In December 2023, a new Net Billing Tariff was implemented for customers who interconnect their qualifying on-site renewable energy generation after April 2023. The new Net Billing Tariff revised the NEM structure for new customers with a retail export compensation rate that is better aligned with the value provided to the grid by behind-the-meter energy generation systems and retail import rates that encourage electrification and adoption of solar systems paired with storage. The new Net Billing Tariff is designed to compensate customers for the value of their exports to the grid based on avoided cost. In addition, prior to the fourth quarter of 2025, the electric residential rate structure in California was primarily based on consumption volume, which placed a higher rate burden on customers with higher electric use while subsidizing lower-use customers. In response to California legislation adopted in 2022, the CPUC broadly restructured the way certain residential fixed costs are collected, moving away from volumetric -only charges and incorporating an income-based fixed charge for default residential rates. The intent of such a fixed charge is to allow the utility to collect a greater portion of its fixed costs on a non-volumetric basis, advance the state’s climate goals through end-use electrification and provide a more affordable rate design on average for lower-income customers. The residential fixed charge was implemented in the fourth quarter of 2025. Depending on the effectiveness of the new Net Billing Tariff and fixed charge, which are uncertain, the risks associated with the existing NEM tariff and rate design could continue or increase, including adverse impacts on electricity rates and the reliability of the transmission and distribution system and the potential for increases in customer dissatisfaction, likelihood of noncompliance with CPUC or other safety or operational standards, and power procurement, operating, capital and other costs that may not be recoverable, any of 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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RISKS RELATED TO SEMPRA TEXAS UTILITIES
Operational and Structural Risks
Ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, policies and operations of Oncor.
Various “ring-fencing” measures, governance mechanisms and commitments are in place that create legal and financial separation between Oncor Holdings, Oncor and their subsidiaries, on the one hand, and Sempra and its affiliates and subsidiaries, on the other hand. These measures are designed to enhance Oncor’s separateness from its owners and mitigate the risk that Oncor would be negatively impacted by a bankruptcy or other adverse financial development affecting its owners. These measures subject us and Oncor to various restrictions, including:
▪ seven members of Oncor’s 13-person board of directors must be independent directors in all material respects under the rules of the NYSE in relation to Sempra and its affiliates and any other owners of Oncor, and also must have no material relationship with Sempra or its affiliates or any other owners of Oncor currently or within the previous 10 years; of the six remaining directors, two must be designated by Sempra, two must be designated by Oncor’s minority owner, TTI, and two must be current or former Oncor officers
▪ Oncor will not pay dividends or other distributions (except for contractual tax payments) if (i) a majority of Oncor’s independent directors or any of the directors appointed by TTI determines that it is in the best interest of Oncor to retain such amounts to meet expected future requirements, (ii) the payment would cause Oncor’s debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT, or (iii) unless otherwise allowed by the PUCT, Oncor’s senior secured debt credit rating by any of the Rating Agencies falls below BBB (or Baa2 for Moody’s)
▪ certain “separateness measures” must be maintained to reinforce the legal and financial separation of Oncor from Sempra, including a requirement that dealings between Oncor and Sempra or Sempra’s affiliates (other than Oncor Holdings and its subsidiaries) must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or membership interests for any entity other than Oncor
▪ a majority of Oncor’s independent directors and the directors designated by TTI that are present and voting (with at least one required to be present and voting) must approve any annual or multi-year budget if the aggregate amount of capital expenditures or O&M in the budget differs by more than 10% from the corresponding amounts in the budget for the preceding fiscal year or multi-year period, as applicable
As a result of these measures, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning, risk management, climate-related activities, cybersecurity practices and other important matters. Moreover, all directors of Oncor, including the directors we have appointed, have considerable autonomy and have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may in some cases be contrary to our interests. To the extent the directors approve or Oncor otherwise pursues actions that are not in our interest, our results of operations, financial condition, cash flows and/or prospects may be materially adversely affected.
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Industry-Related Risks
Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or ERCOT market could negatively affect Oncor.
Oncor operates in the electric utility industry and is subject to many of the same or similar risks as SDG&E and SoCalGas as we describe above under “Risks Related to All Sempra Businesses” and “Risks Related to Sempra California,” particularly with respect to our operational risks, financial risks and specifically regulation by federal, state, and local legislative and regulatory authorities regarding rates and other financial and operational matters. Oncor is subject to a complex regulatory oversight structure with several different regulators, including the PUCT, FERC, North American Electric Reliability Corporation and Texas Reliability Entity, Inc. Oncor operates in the ERCOT market, which is subject to oversight by the PUCT and the Texas legislature, either of which could impose changes to the ERCOT market that could impact Oncor. In ERCOT, rates are set by the PUCT based on a historical test year, and as a result, the rates Oncor is allowed to charge generally will not exactly match its costs at any given point in time and it may not be able to timely or fully recover its actual costs and/or earn its full return on invested capital, particularly during periods of increased capital spending by Oncor, high inflation, or increases in interest rates, storm-related costs, and other operating costs relative to Oncor’s most recent base rate review. Further, the levels and timing of any approved recovery could significantly differ from Oncor’s requests. In addition to requests to recover its costs, Oncor’s rate proceedings may contain other requests. Failure to receive approval of its requests in any rate proceeding could adversely impact Oncor, and those impacts could be material.
The costs and burdens of complying with the various federal, state, and local legislative and regulatory requirements applicable to Oncor and adjusting Oncor’s business and operations in response to legislative and regulatory developments, including changes in ERCOT, and any fines or penalties that could result from any noncompliance, may have a material adverse effect on Oncor. In addition, insufficient electric generation capacity within ERCOT or significant changes within ERCOT or to the ERCOT market structure that impact transmission and distribution utilities, including adverse publicity or public perception or additional regulatory requirements or oversight, could materially adversely affect Oncor. Moreover, legislative, regulatory, market or industry activities could adversely impact Oncor’s collections and cash flows and jeopardize the predictability of utility earnings. For instance, in June 2025, legislation was signed into law to reduce regulatory lag on transmission and distribution capital investments through the UTM process, which we describe in “Part I – Item 1. Business – Ratemaking Mechanisms.” Oncor anticipates filing a UTM on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result has recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. However, the PUCT has not finalized rules with respect to use of the UTM, and as a result any positions Oncor has taken with respect to interpreting the legislation could be revised as a result of the PUCT’s final rules and interpretations, and such revisions could have a material adverse impact on our results of operations, financial condition, cash flows and/or prospects.
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.
If Oncor does not successfully manage these risks and respond to any other applicable legislative, regulatory, market or industry developments, Oncor could suffer a deterioration in its results of operations, financial condition, cash flows and/or prospects, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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Financial Risks
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 desiredimprovements 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.
Because our commitments to the PUCT prohibit us from making loans to Oncor, we may elect to increase our capital contributions to Oncor if it is unable to meet its capital requirements, access sufficient capital, or raise capital on favorable terms. Any such investments could be substantial, would reduce the cash available to us for other purposes, may not be recovered, and could increase our indebtedness, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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Sempra could incur substantial tax liabilities if EFH’s 2016 spin-off of Vistra is deemed to be taxable.
As part of its bankruptcy proceedings, in 2016, EFH distributed all the outstanding shares of common stock of its subsidiary Vistra Corp. (formerly Vistra Energy Corp. and referred to herein as Vistra) to certain creditors of TCEH LLC (the spin-off), and Vistra became an independent, publicly traded company. Vistra’s spin-off from EFH was intended to qualify for partially tax-free treatment to EFH and its shareholders under Sections 368(a)(1)(G), 355 and 356 of the U.S. Internal Revenue Code of 1986 (as amended) (collectively referred to as the Intended Tax Treatment). In connection with and as a condition to the spin-off, EFH received a private letter ruling from the IRS regarding certain issues relating to the Intended Tax Treatment, as well as tax opinions from counsel to EFH and Vistra regarding certain aspects of the spin-off not covered by the private letter ruling.
In connection with the merger of EFH with a subsidiary of Sempra in 2018 (the Merger), EFH received a supplemental private letter ruling from the IRS and Sempra and EFH received tax opinions from their respective counsels that generally provide that the Merger will not affect the conclusions reached in, respectively, the IRS private letter ruling and tax opinions issued with respect to the spin-off described above. Similar to the IRS private letter ruling and opinions issued with respect to the spin-off, the supplemental private letter ruling is generally binding on the IRS and any opinions issued with respect to the Merger are based on factual representations and assumptions, as well as certain undertakings, made by Sempra and EFH. If such representations and assumptions are untrue or incomplete, any such undertakings are not complied with, or the facts upon which the IRS supplemental private letter ruling or tax opinions (which will not impact the IRS position on the transactions) are based are different from the actual facts relating to the Merger, the tax opinions and/or supplemental private letter ruling may not be valid and could be challenged by the IRS. Even though Sempra Texas Holdings Corp. would have administrative appeal rights if the IRS were to invalidate its private letter ruling and/or supplemental private letter ruling, including the right to challenge any adverse IRS position in court, any such appeal would be costly, subject to uncertainties and could fail. If it is ultimately determined that the Merger caused the spin-off not to qualify for the Intended Tax Treatment, Sempra, through its ownership of Sempra Texas Holdings Corp., could incur substantial tax liabilities, which would materially reduce the value associated with our investment in Oncor and could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
RISKS RELATED TO SEMPRA INFRASTRUCTURE
Operational Risks
Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels or generate expected earnings or cash flows.
Energy Infrastructure Projects
We are involved in a number of energy infrastructure projects in various stages of development and construction, which subject us to numerous risks. Success in developing each project depends on, among other things:
▪ our financial condition and cash flows and other factors that impact our ability to invest sufficient funds in the project, including for preliminary activities conducted before we determine whether the project is viable
▪ project assessment and design and our ability to foresee and incorporate emerging trends and technologies
▪ our ability to reach a positive FID or meet other milestones, which may be influenced by factors outside our control, including the global economy and energy and financial markets, actions by regulators, internal and external approval requirements, and many of the other factors described in this risk factor
▪ negotiation of satisfactory EPC agreements and renegotiation in the event of delays in reaching an FID or other specified deadlines
▪ identification of suitable partners, customers, contractors, suppliers and other necessary counterparties
▪ progressing relationships from MOUs, HOAs or other non-binding arrangements to execution of binding, definitive agreements
▪ negotiation and maintenance of satisfactory equity, purchase, sale, supply, transportation and other appropriate commercial agreements, and satisfaction of any conditions to effectiveness of such agreements, including reaching an FID within agreed timelines
▪ timely receipt and maintenance of required governmental permits, licenses and other authorizations on acceptable terms
▪ our project partners’, contractors’, equipment providers’, lenders’ and other vendors’ and counterparties’ willingness and financial or other ability to fulfill their contractual commitments
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▪ timely, satisfactory and on-budget completion of construction, which could be negatively affected by engineering problems; stakeholder relations issues, such as the opposition by some members of the Yaqui tribe to the construction of the Guaymas-El Oro segment of the Sonora pipeline, which we discuss in in Note 1 of the Notes to Consolidated Financial Statements; work stoppages; unavailability or increased costs of materials, equipment, labor and commodities due to inflation, tariffs or supply chain or other issues; and a variety of other factors, many of which we discuss above under “Risks Related to All Sempra Businesses – Operational Risks” and elsewhere in this risk factor
▪ 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
▪ obtaining satisfactory financing for the project
▪ the absence of hidden defects or inherited environmental liabilities on the project site
▪ timely and cost-effective resolution of any litigation or unsettled property rights affecting the project
▪ geopolitical events and other uncertainties
Any failures with respect to the above factors or other factors relevant to any particular project could involve additional costs, otherwise negatively affect our ability to successfully complete the project and force us to impair or write off amounts we have invested in the project. If we are unable to complete a development project, if we experience delays, or if construction, financing or other project costs exceed our estimated budgets and we are required to make additional capital contributions, we may not receive an adequate or any return on our investment and other resources expended on the project and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
The operation of existing facilities and any future projects we complete involves many risks, including the potential for unforeseen design flaws, engineering challenges, or breakdowns of facilities, equipment or processes; labor disputes or shortages; fuel interruption; environmental contamination; increasing regulatory requirements, including from regulations aiming to reduce GHG emissions; and the other operational risks that we discuss above under “Risks Related to All Sempra Businesses – Operational Risks.” Any of these events could lead to our facilities being idle or operating below expected levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
LNG Projects
In addition to the risks described above that are applicable to all our energy infrastructure projects, our LNG projects, which we discuss in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure,” also face distinct disadvantages relative to some LNG projects being pursued by other project developers, including:
▪ The proposed Cameron LNG Phase 2 project is subject to certain restrictions and conditions under the JV project financing agreements for the Cameron LNG Phase 1 facility and requires unanimous consent of all the members, including with respect to the equity investment obligation of each member. We may not be able to satisfy these conditions, receive members’ consent, obtain satisfactory conclusion on the EPC process, or obtain the extension of our non-FTA approval, in which case our ability to develop the Cameron LNG Phase 2 project would be jeopardized.
▪ The ECA LNG projects under construction and in development are subject to the Mexican regulatory process and an overlay of U.S. regulation for natural gas exports to LNG facilities in Mexico, which are not well developed and, among other factors, contributed to delays in obtaining a necessary permit from the Mexican government for the ECA LNG Phase 1 project and could cause similar delays or other hurdles in the future. In September 2025, we submitted a filing with the DOE to extend the construction deadline associated with our non-FTA permits for the ECA LNG Phase 1 project until the end of summer 2026, but we may not receive this extension on a timely basis or at all. In addition, the Baja California region does not have extensive sources of natural gas, and at times, natural gas supply to the region is severely constrained and may impact our costs and our ability to source all feed gas required under our ECA LNG Phase 1 supply contracts. Further, while we do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility, we expect construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has a firm storage and nitrogen injection service agreement with Shell that expires in May 2028.
▪ The PA LNG Phase 1 project under construction is located at a greenfield site and is therefore subject to certain disadvantages relative to projects being constructed or developed at brownfield sites, such as increased time and costs to develop and construct the project due to lack of existing infrastructure. The PA LNG Phase 2 project under construction is located at the site of the PA LNG Phase 1 project and is therefore subject to potential disadvantages, such as increased complexity of integrating new facilities with existing infrastructure.
Development and operation of these or any other LNG projects will depend on the expansion of our existing pipeline interconnections or the ability to permit and construct new pipeline facilities, each of which may require us to enter into additional pipeline interconnection agreements with third-party pipelines, which may not be possible on reasonable terms or at all.
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The capital requirements for our LNG projects can be significant, even if we do not reach a positive FID. As has happened in the past, our proposed facilities may not be completed in accordance with estimated timelines or budgets or at all as a result of the above or other factors, and delays, cost overruns or our inability to complete one or more of these projects could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We face risks from increasing competition.
The markets in which we operate are characterized by numerous capable competitors, many of which have extensive and diversified development and/or operating experience domestically and internationally and financial resources similar to or greater than ours. In particular, the natural gas pipeline, storage and LNG market segments have been characterized by strong and increasing competition for winning new development projects and acquiring existing assets. These competitive factors could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We are exposed to additional competitive risks in connection with our LNG projects. Our ability to reach a positive FID for each development project and, if a project is completed, the overall success of the project depend in part on global energy markets, which can increase competition for global LNG demand in a number of ways. In general, depressed natural gas and LNG prices in the markets intended to be served by any of our projects, including as a result of global oil prices and their associated current and forward projections or other factors, could reduce the pricing and cost advantages of exporting natural gas and LNG produced in North America, which could lead to decreased demand from our projects. Although demand for natural gas is currently strong due to increased focus on energy security and climate aims, a reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, reduced economic activity in general, or as a result of calls by some to limit or eliminate global reliance on natural gas. Further, because LNG projects take a number of years to develop and construct, it is difficult to match current and expected demand with the projected supply from projects under development. Moreover, shifts in U.S. and foreign energy policy could impact supply, demand and other matters critical to LNG projects, such as permitting and other approval processes. These factors could delay or hamper the development of U.S. LNG export facilities and make LNG projects in other parts of the world more feasible and competitive with LNG projects in North America, thus increasing supply and competition for global LNG demand. Any of these occurrences could impact competition and prospects for developing LNG projects and negatively affect the performance and prospects of any of our projects that are or become operational, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We may not be able to secure, maintain, extend or replace long-term supply, sales or capacity agreements.
Certain of SI Partners’ projects, including the ECA Regas Facility, Cameron LNG JV and all of its LNG projects under construction, have long-term agreements with a limited number of customers. The long-term nature of these agreements and the small number of customers exposes us to risks, including increased credit risks and amplified impacts of disputes or other similar issues, which we have experienced in the past. Any such issues that arise in the future with respect to these long-term contracts could lead to significant legal and other costs, result in termination of certain key contracts and negatively impact the reliability of revenues from the applicable projects and the prospects of any implicated development projects. Any such event could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
SI Partners’ obligations and those of its counterparties, such as its LNG customers, are contractually subject to suspension or termination for force majeure events, which generally are beyond the control of the parties. Force majeure declarations may have attendant negative consequences, such as loss or deferral of revenue arising from non-deliveries of natural gas from suppliers or LNG to customers in certain circumstances. Also, certain force majeure events may impact the contractors constructing SI Partners’ projects, which may result in delays or increased costs. SI Partners may have limited available remedies, including limitations on damages that may prohibit recovery of all costs incurred. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
SI Partners’ ability to secure new or maintain or extend existing long-term sales or capacity agreements for its natural gas pipeline operations depends on, among other factors, demand for and supply of LNG and/or natural gas from its transportation customers, which may include our LNG facilities. A decrease in demand for or supply of LNG or natural gas from such customers or the occurrence of other events that hinder SI Partners from maintaining such agreements or establishing new ones could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
The electric generation and wholesale power sales industries are highly competitive. As more plants are built, supplies of energy and related products may exceed demand, competitive pressures may increase and wholesale electricity prices may decline or become more volatile. Without long-term power sales agreements, our revenues may be subject to increased volatility, and we may be unable to sell the power that SI Partners’ facilities can produce at favorable prices or at all, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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We rely on transportation assets and services, much of which we do not control, to deliver natural gas and electricity.
We depend on electric transmission lines, natural gas pipelines and other transportation facilities and services owned and operated by third parties to, among other things:
▪ deliver the natural gas, LNG, electricity and LPG we sell to customers or use at our LNG facilities
▪ supply natural gas to our gas storage and electric generation facilities
▪ provide retail energy services to customers
If transportation is disrupted, the construction of necessary interconnecting infrastructure is not completed on schedule or at all or capacity is inadequate, we may be delayed in completing projects under development and/or unable to meet our contractual obligations to customers of those projects or existing projects, in which case we may be responsible for damages they incur, such as the cost of acquiring alternative supplies at then-current spot market rates, and we could lose customers that may be difficult to replace. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Financial Risks
Fixed-price long-term contracts for services or commodities expose our businesses to risks.
SI Partners seeks long-term contracts for services and commodities to better utilize its facilities, reduce volatility in earnings and support the construction of new infrastructure. Certain of these contracts are at fixed prices, and their profitability may be negatively affected by inflation, tariffs, rising interest rates and changes in applicable exchange rates. We aim to mitigate these risks by, among other things, using variable pricing tied to market indices, contracting for direct pass-through of operating costs and/or entering into hedges. However, these measures may not fully or substantially offset any increases in operating expenses or financing costs and their use could introduce additional risks, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Our international businesses and operations expose us to foreign currency exchange rate and inflation risks.
Our operations in Mexico pose foreign currency exchange rate and inflation risks. Exchange and inflation rates with respect to Mexico and fluctuations in those rates may have an impact on the revenue, cash flows and costs from our international operations, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We sometimes attempt to hedge cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments, but these hedges may not fully achieve our objectives of mitigating earnings volatility that would otherwise occur due to exchange rate fluctuations. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations for entities whose functional currencies are not the U.S. dollar. Moreover, Mexico has experienced periods of high inflation and exchange rate instability in the past, and severe devaluation of the Mexican peso could result in governmental intervention to institute restrictive exchange control policies, as has occurred in Mexico and other Latin American countries. We discuss our foreign currency exposure at our Mexican subsidiaries in “Part II – Item 7. MD&A” and “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Our businesses are exposed to fluctuations in commodity prices.
We buy energy-related commodities from time to time for pipeline operations, LNG facilities or power plants to satisfy contractual obligations with customers. The regional and other markets in which we purchase these commodities are competitive and can be subject to significant pricing volatility. Our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities we buy change in a direction or manner not anticipated and for which we have not provided adequately through purchase or sale commitments or other hedging transactions.
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.
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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.
Legal and Regulatory Risks
Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical, credit and management oversight risks and challenges.
We own or have interests in a variety of energy infrastructure assets in Mexico, and we do business with companies based in foreign markets, including particularly our LNG export operations. Conducting these activities in foreign jurisdictions subjects us to complex management, security, political, legal, economic and financial risks that vary by country, many of which may differ from and potentially be greater than those associated with our wholly domestic businesses, and the occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. These risks include the following and the other risks discussed in this risk factor below:
▪ compliance with tax, trade, environmental and other foreign laws and regulations, including legal limitations on ownership in some foreign countries and inadequate or inconsistent enforcement of regulations
▪ actions by local regulatory bodies, such as the CNE, including setting rates and tariffs that may be earned by or charged to our businesses
▪ adverse changes in social, geopolitical, economic or market conditions
▪ adverse rulings by or instability in foreign courts or tribunals
▪ challenges obtaining, maintaining and complying with permits or approvals
▪ difficulty enforcing contractual and property rights and differing legal standards
▪ expropriation or theft of assets
▪ the stability of foreign governments or such foreign governments’ relations with the U.S. government
▪ changes in the priorities and budgets of international customers, which may be driven by many of the factors listed above, among others
Mexican Government Influence on Economic and Energy Matters
The Mexican government exercises significant and increasing influence over the Mexican energy sector and has adopted additional changes that could impact private investment in this sector.
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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Although the new laws, regulations, and certain general administrative provisions in the energy sector have been published, the extent of the impact of the 2025 Energy Laws remains uncertain. These laws and future implementation of existing and any new regulations could adversely affect SI Partners’ ability to secure favorable rate cases and operate its existing assets at their current levels; result in increased costs to SI Partners and its customers; adversely impact SI Partners’ ability to secure and retain permits and develop new projects in Mexico; result in decreased revenues and/or cash flows; and negatively impact SI Partners’ ability to recover the carrying values of its investments in Mexico, any of which could have a material adverse impact on our business, results of operations, financial condition, cash flow and/or prospects.
In addition to the constitutional changes noted above, in 2024 the Mexican government introduced significant changes to the Mexican Constitution, including reforms requiring that all judges be elected rather than appointed, which may adversely impact, among other things, SI Partners’ ability to enforce its contracts with state-owned enterprises or challenge actions taken by regulators. These reforms and any further Mexican Constitutional, legal or regulatory changes could adversely affect the Mexican economy, energy sector and our businesses, the extent of which we currently are unable to predict.
U.S. and Foreign Laws and International Relations
Our international business activities are subject to laws and regulations in the U.S. and Mexico and other countries where we do business related to foreign operations and doing business internationally, including the U.S. Foreign Corrupt Practices Act, the Mexican Federal Anticorruption Law in Public Contracting (Ley Federal Anticorrupción en Contrataciones Públicas) and similar laws, and are sensitive to geopolitical factors in each of these countries. The current and the last U.S. Administrations have taken different stances with respect to international trade agreements, tariffs, immigration and other matters of foreign policy that impact trade and foreign relations. We discuss developments in tariff policies above under “Risks Related to All Sempra Businesses – Operational Risks.” Shifts in other aspects of foreign policy could create uncertainty and result in or increase adverse effects on our businesses. Violations or allegedviolations of the laws referred to above, as well as foreign policy positions or sanctions, could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We face risks related to unsettled property rights and titles in Mexico.
We are engaged in a dispute regarding our title to property in Mexico adjacent to and owned by the ECA Regas Facility, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. In addition, we have and may in the future seek to obtain long-term leases or rights-of-way from governmental agencies or other third parties to operate our energy infrastructure on land we do not own. In addition to the risks associated with such property ownership and use that we describe above under “Risks Related to All Sempra Businesses – Operational Risks,” disputes regarding ownership or rights to any of these properties could lead to difficulties developing, constructing and, if completed, operating the affected facilities or proposed projects. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
SI Partners’ energy infrastructure assets may be considered by the Mexican government to be a public service or essential for the provision of a public service, in which case these assets and the related businesses could be subject to expropriation or nationalization, loss of concessions, renegotiation or annulment of existing contracts, and other similar risks. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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Risk Related to Planned Sales of Certain Assets and Businesses
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.
Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
operation and maintenance expense
OBBBA
One Big Beautiful Bill Act of 2025
OCI
other comprehensive income (loss)
OEIS
Office of Energy Infrastructure Safety
Oncor
Oncor Electric Delivery Company LLC
Oncor Holdings
Oncor Electric Delivery Holdings Company LLC
OSHA
Occupational Safety and Health Administration
Other Sempra
All Sempra consolidated entities, except for SDG&E and SoCalGas
PA2 JVCo
a subsidiary of SI Partners that owns Port Arthur LNG II
PA2 JVCo LLCA
PA2 JVCo’s limited liability company agreement
PA LNG Phase 1 project
initial phase of the Port Arthur LNG liquefaction project
PA LNG Phase 2 project
second phase of the Port Arthur LNG liquefaction project
Pipeline and Hazardous Materials Safety Administration
Port Arthur LNG I
Port Arthur LNG, LLC, a subsidiary of SI Partners that owns the PA LNG Phase 1 project
Port Arthur LNG II
Port Arthur LNG Phase II, LLC, a subsidiary of SI Partners that owns the PA LNG Phase 2 project
property, plant and equipment
PPA
power purchase agreement
PRP
Potentially Responsible Party
PSEP
Pipeline Safety Enhancement Plan
PUCT
Public Utility Commission of Texas
PURA
Texas Public Utility Regulatory Act
Rating Agencies
Moody’s, S&P and Fitch, collectively
REC
renewable energy certificate
Registrants
has the meaning set forth in Rule 12b-2 under the Exchange Act and consists of Sempra, SDG&E and SoCalGas for purposes of this report
ROE
return on equity
ROU
right-of-use
RPS Program
Renewables Portfolio Standard program
RSU
restricted stock unit
S&P Global Ratings, a division of S&P Global Inc.
Sales Agreement
ATM Equity Offering Sales Agreement, dated November 6, 2024, among Sempra and Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, Morgan Stanley & Co. LLC, MUFG Securities Americas Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc., and Wells Fargo Securities, LLC (each a sales agent or forward seller) and Barclays Bank PLC, Bank of America, N.A., Citibank, N.A., Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, Morgan Stanley & Co. LLC, MUFG Securities EMEA plc, Royal Bank of Canada, The Bank of Nova Scotia and Wells Fargo Bank, National Association, or one of their respective affiliates (each a forward purchaser)
California Senate Bill
scope 1 GHG emissions
a company’s direct GHG emissions from operations that it owns or controls
scope 2 GHG emissions
a company's indirect GHG emissions such as purchased electricity for its own use at its facilities
SDG&E
San Diego Gas & Electric Company
SDSRA
Senior Debt Service Reserve Account
SEC
U.S. Securities and Exchange Commission
SEDATU
Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexico’s agency in charge of agriculture, land and urban development)
SENER
Secretaría de Energía de México (Mexico’s Ministry of Energy)
series C preferred stock
Sempra’s 4.875% fixed-rate reset cumulative redeemable perpetual preferred stock, series C
Sharyland Holdings
Sharyland Holdings, L.P.
Sharyland Utilities
Sharyland Utilities, L.L.C.
Shell
Shell México Gas Natural, S. de R.L. de C.V.
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GLOSSARY
SI Partners
Sempra Infrastructure Partners, LP, the holding company for most of Sempra’s businesses not subject to California or Texas utility regulation
SoCalGas
Southern California Gas Company
SOFR
Secured Overnight Financing Rate
SONGS
San Onofre Nuclear Generating Station
SPA
sale and purchase agreement
SST Committee
Safety, Sustainability and Technology Committee of the Sempra board of directors
Support Agreement
support agreement, dated July 28, 2020 and amended in June 2021 and January 2025, between Sempra and Sumitomo Mitsui Banking Corporation
TAG Norte
TAG Norte Holding, S. de R.L. de C.V.
TAG Pipelines
TAG Pipelines Norte, S. de R.L. de C.V.
Tangguh PSC
Tangguh PSC Contractors
TCEQ
Texas Commission on Environmental Quality
TCJA
Tax Cuts and Jobs Act of 2017
TdM
Termoeléctrica de Mexicali
Electric Transmission Owner Formula Rate, effective June 1, 2019 through May 31, 2025
TO5 adder refund provision
the provision in the TO5 settlement providing that SDG&E will refund the California ISO adder as of June 1, 2019 if the FERC issues an order ruling that California IOUs are no longer eligible for the California ISO adder
Electric Transmission Owner Formula Rate, effective June 1, 2025, subject to refund
TTI
Texas Transmission Investment LLC, an entity indirectly owned by OMERS Administration Corporation (acting through its infrastructure investment entity, OMERS Infrastructure Management Inc.) and GIC Private Limited
U.S. GAAP
generally accepted accounting principles in the United States of America
UTM
unified tracker mechanism
VaR
value at risk
Ventika
Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V., collectively
VIE
variable interest entity
Wildfire Fund
the fund established pursuant to AB 1054
WMP
wildfire mitigation plan
In this report, references to “Sempra” are to Sempra and its consolidated entities, collectively, and references to “we,” “our,” “us” and “our company” are to the applicable Registrant and its consolidated entities, collectively, in each case unless otherwise stated or indicated by the context. All references in this report to our reportable segments are not intended to refer to any legal entity with the same or similar name.
Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:
▪ the Consolidated Financial Statements and related Notes of Sempra;
▪ the Financial Statements and related Notes of SDG&E; and
▪ the Financial Statements and related Notes of SoCalGas.
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based on assumptions about the future, involve risks and uncertainties, and are not guarantees. Future results may differ materially from those expressed or implied in any forward-looking statement. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or otherwise.
Forward-looking statements can be identified by words such as “believe,” “expect,” “intend,” “anticipate,” “contemplate,” “plan,” “estimate,” “project,” “forecast,” “envision,” “should,” “could,” “would,” “will,” “confident,” “may,” “can,” “potential,” “possible,” “proposed,” “in process,” “construct,” “develop,” “opportunity,” “preliminary,” “pro forma,” “strategic,” “initiative,” “target,” “outlook,” “optimistic,” “poised,” “positioned,” “maintain,” “continue,” “progress,” “advance,” “goal,” “aim,” “commit,” or similar expressions, or when we discuss our guidance, priorities, strategies, goals, vision, mission, projections, intentions or expectations.
Factors, among others, that could cause actual results and events to differ materially from those expressed or implied in any forward-looking statement include:
▪ California wildfires, including potential liability for damages regardless of fault and any inability to recover all or a substantial portion of costs from insurance, the Wildfire Fund and the Continuation Account, rates from customers or a combination thereof
▪ decisions, disallowances or denials of cost recovery, audits, investigations, inquiries, ordered studies, regulations, denials or revocations of permits, consents, approvals or other authorizations, renewals of franchises, and other actions, including the failure to honor contracts and commitments, by the (i) CNE, CPUC, DOE, FERC, IRS, PUCT and other regulatory bodies and (ii) U.S., Mexico and states, counties, cities and other jurisdictions therein and in other countries where we do business
▪ the success of business development efforts, construction projects, acquisitions, divestitures, and other significant transactions, such as the planned sale of a portion of our equity interest in SI Partners, including risks related to, as applicable, (i) being able to reach a positive FID, (ii) negotiating pricing and other terms in definitive contracts, (iii) completing construction projects or other transactions on schedule and budget, (iv) realizing anticipated benefits from any of these efforts if completed, (v) obtaining regulatory and other approvals and (vi) third parties honoring their contracts and commitments, including with respect to closing or post-closing payments
▪ changes to our capital expenditure plans and their potential impact on rate base or other growth
▪ changes, due to evolving economic, political and other factors, to (i) trade and other foreign policy, including the imposition of tariffs by the U.S. and foreign countries, and (ii) laws and regulations, including those related to tax and the energy industry in the U.S. and Mexico
▪ litigation, arbitration, property disputes and other proceedings
▪ cybersecurity threats, including by nation-state actors, of ransomware or other attacks on our systems, the energy grid or our other infrastructure, or the systems of third parties with which we conduct business
▪ the availability, uses, sufficiency, and cost of capital resources and our ability to borrow money or otherwise raise capital on favorable terms and meet our obligations, which can be affected by, among other things, (i) actions by credit rating agencies to downgrade our credit ratings or place those ratings on negative outlook, (ii) instability in the capital markets, and (iii) fluctuating interest rates and inflation
▪ the impact of efforts to increase affordability of U.S. utility customer rates on our ability to obtain cost recovery from applicable regulators, our capital expenditure and other growth plans and our ability to advance statewide policies
▪ the impact on affordability of customer rates, cost of capital and operating margin due to (i) volatility in inflation, interest rates, commodity prices, tariff rates, and foreign currency exchange rates and (ii) with respect to SDG&E’s and SoCalGas’ businesses, the cost of meeting the demand for lower carbon and reliable energy in California
▪ the impact of climate policies, laws, rules, regulations, trends and required disclosures, including actions to reduce or eliminate reliance on natural gas, increased uncertainty in the political or regulatory environment for California natural gas distribution companies, the risk of nonrecovery for stranded assets, and uncertainty related to emerging technologies
▪ weather, natural disasters, pandemics, accidents, equipment failures, explosions, terrorism, information system outages or other events, such as work stoppages, that disrupt our operations, damage our facilities or systems, cause the release of harmful materials or fires or subject us to liability for damages, fines and penalties, some of which may not be recoverable through regulatory mechanisms or insurance or may impact our ability to obtain satisfactory levels of affordable insurance
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▪ the availability of electric power, natural gas and natural gas storage and transportation capacity, including disruptions caused by failures in the transmission grid or pipeline and storage systems or limitations on the injection and withdrawal of natural gas from storage facilities
▪ Oncor’s ability to reduce or eliminate its quarterly dividends due to regulatory and governance requirements and commitments, including by actions of Oncor’s independent directors or a minority member director
▪ other uncertainties, some of which are difficult to predict and beyond our control
We caution you not to rely unduly on any forward-looking statements. You should review and carefully consider the risks, uncertainties and other factors that affect our businesses as described herein and in other reports we file with the SEC.
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SUMMARY OF RISK FACTORS
There are a number of risks you should understand before making an investment decision in our securities or the securities of our businesses. This summary is not intended to be complete and should only be read together with the information set forth in “Part I – Item 1A. Risk Factors” in this report. If any of these risks occur, Sempra’s and its businesses’ results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, and the trading price of Sempra’s securities and those of its businesses could decline. These risks include the following:
Risks Related to Sempra
▪ Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments
▪ Successfully executing our five-year capital expenditures plan is subject to risks
▪ The economic interest, voting rights and market value of our outstanding common stock may be adversely affected by any additional equity securities we may issue
Risks Related to All Sempra Businesses
▪ Our infrastructure and its supporting systems subject us to risks
▪ We face risks related to severe weather, natural disasters, physical attacks and other similar events
▪ We face evolving cybersecurity, technology resiliency and data security and governance risks, including with respect to increasing use of artificial intelligence
▪ Our debt service obligations expose us to risks
▪ The availability and cost of financing could be negatively affected by market and economic conditions and other factors
▪ Credit rating agencies may downgrade our credit ratings or place them on negative outlook, and our efforts to maintain these ratings could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects in development
▪ We face risks related to the evolving regulatory environment, including failures or delays in obtaining and maintaining franchises and other required approvals and potential negative impacts of our legislative and regulatory advocacy efforts
▪ We face risks related to environmental and climate change regulation and the costs of the energy transition
▪ We are subject to complex tax and accounting requirements that expose us to risks
Risks Related to Sempra California
▪ Wildfires in California pose risks to Sempra, SDG&E and SoCalGas
▪ The electricity industry is undergoing significant change
▪ Natural gas continues to be the subject of political and public debate, including a desire by some to reduce or eliminate reliance on natural gas as an energy source
▪ SDG&E and SoCalGas are subject to extensive regulation
Risks Related to Sempra Texas Utilities
▪ Ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, policies and operations of Oncor
▪ Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or ERCOT market could negatively affect Oncor
▪ Oncor’s capital expenditures plan may not be executed as planned or achieve its business objectives
▪ Oncor’s capital expenditures plan will result in significant liquidity needs that may necessitate additional investments
Risks Related to Sempra Infrastructure
▪ Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels or generate expected earnings or cash flows
▪ We may not be able to secure, maintain, extend or replace long-term supply, sales or capacity agreements
▪ Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical, credit and management oversight risks and challenges
Risks Related to Planned Sales of Certain Assets and Businesses
▪ 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
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PART I.
ITEM 1. BUSINESS
OVERVIEW
We are a holding company whose principal businesses are regulated utilities in California and Texas. Our businesses invest in and operate electric and gas utilities and other energy infrastructure that provide energy services to customers.
Sempra was formed in 1998 through a business combination of Enova Corporation and Pacific Enterprises, the holding companies of our regulated public utilities in California: SDG&E, which began operations in 1881, and SoCalGas, which began operations in 1867. We have since expanded our regulated public utility presence into Texas through our 80.25% interest in Oncor and 50% interest in Sharyland Utilities. Sempra Infrastructure’s assets include investments in the U.S. and Mexico with a focus on LNG, energy networks and low carbon solutions.
Business Strategy
Sempra’s mission is to build America’s leading utility growth business. We are primarily focused on the largest economies in the U.S., California and Texas, where we are investing in regulated utilities with a view toward producing stable cash flows and improved earnings visibility. Our goal is to deliver safe, reliable and affordable energy to customers while increasing shareholder value.
DESCRIPTION OF BUSINESS BY SEGMENT
Sempra’s business activities are organized under the following reportable segments:
▪ Sempra California
▪ Sempra Texas Utilities
▪ Sempra Infrastructure
SDG&E and SoCalGas each have one reportable segment.
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Sempra California
SDG&E
SDG&E is a regulated public utility that provides electric services to a population of, at December 31, 2025, approximately 3.6 million and natural gas services to approximately 3.3 million of that population, covering an approximate 4,100 square mile service territory in Southern California that encompasses San Diego County and an adjacent portion of Orange County.
SDG&E’s assets at December 31, 2025 covered the following territory:
We describe SDG&E’s electric utility operations below. We describe SDG&E’s natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.” For a discussion of the risks and uncertainties facing SDG&E’s business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California.”
Electric Transmission and Distribution System. Service to SDG&E’s customers is supported by its electric transmission and distribution system, which includes substations and overhead and underground lines. These electric facilities are primarily in the San Diego, Imperial and Orange counties of California and in Arizona and Nevada and consisted of 2,018 miles of transmission lines, 24,210 miles of distribution lines and 158 substations at December 31, 2025. Occasionally, various areas of the service territory require expansion to accommodate customer growth and maintain reliability and safety.
SDG&E’s 500-kV Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,163 MW, although it can be less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed by SDG&E that extends across Southern California. Both of these lines are operated by the California ISO and together provide SDG&E with import capability of 3,900 MW of power.
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Mexico’s Baja California transmission system is connected to SDG&E’s system via two 230-kV interconnections with combined capacity of up to 600 MW in the north-to-south direction and 800 MW in the south-to-north direction. However, it can be less under certain system conditions.
SDG&E’s system is connected to Edison’s transmission system via five 230-kV transmission lines.
Electric Resources. SDG&E supplies power from its own electric generation facilities and procures power on a long-term basis from other suppliers for resale through CPUC-approved PPAs or purchases on the spot market. SDG&E does not earn any return on commodity sales volumes. SDG&E’s electric resources at December 31, 2025 were as follows:
ELECTRIC RESOURCES (1)
Contract
expiration date
Net operating
capacity (MW)
% of total
SDG&E:
Owned generation facilities, natural gas (2)
PPAs:
Renewable energy:
Wind
Solar
Other
2027 and thereafter
Tolling and other
Total
(1) Excludes approximately 482 MW of energy storage owned and approximately 632 MW of energy storage contracted.
(2) SDG&E owns and operates four natural gas-fired power plants, three of which are in California and one is in Nevada.
Charges under contracts with suppliers are based on the amount of energy received or are tolls based on available capacity. Tolling contracts are PPAs under which SDG&E provides natural gas to the energy supplier.
SDG&E procures natural gas under short-term contracts for its owned generation facilities and for certain tolling contracts associated with PPAs. Purchases from various southwestern U.S. suppliers are primarily priced based on published monthly bid-week indices, which can be subject to volatility.
SDG&E participates in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers throughout the U.S. and Canada. Participants can make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.
Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:
ELECTRIC CUSTOMER METERS AND VOLUMES
Customer meter count
Volumes (1)
(millions of kWh)
December 31,
Years ended December 31,
SDG&E:
Residential
Commercial
Industrial
Street and highway lighting
CCA and DA
Total
(1) Includes intercompany sales.
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SDG&E currently provides procurement service for a portion of its customer load. Most customers receive electric commodity service from a load-serving entity other than SDG&E through programs such as CCA and DA. In such cases, SDG&E no longer procures energy for this departed load. Accordingly, SDG&E’s CCA and DA customers receive primarily transportation and distribution services from SDG&E.
CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, and DA is currently limited by a cap based on gigawatt hours. Several jurisdictions in SDG&E’s territory have implemented CCA, including the City of San Diego in 2022.
Due to this departed load, SDG&E’s historical energy procurement commitments for future deliveries exceed the needs of its remaining bundled customers. To help achieve the goal of ratepayer indifference (as to whether customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The framework is intended to more equitably allocate SDG&E’s historical energy procurement cost obligations among customers served by SDG&E and customers now served by CCA and DA.
San Diego’s mild climate contributes to lower consumption by our customers. Rooftop solar installations continue to reduce residential and commercial volumes sold by SDG&E. At December 31, 2025, 2024 and 2023, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 2,452 MW, 2,318 MW and 2,154 MW, respectively.
Electricity demand is dependent on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preferences, environmental regulations, legislation, renewable power generation, demand-side management impact and DER, among other factors. California’s energy policy supports increased electrification, which could increase electric volumes sold in the coming years. Other external factors, such as the price of purchased power, the use and further development of renewable energy sources and energy storage, the development of or requirements for new natural gas supply sources, demand for and supply of natural gas and general economic conditions, can also result in significant shifts in the market price of electricity, which may in turn impact demand. Electricity demand is also impacted by seasonal weather patterns (or “seasonality”), tending to increase in the summer months to meet the cooling load and in the winter months to meet the heating load.
Competition. SDG&E faces competition to serve its customer load from distributed and local power generation growth, including DER. In addition, the electric industry is undergoing rapid technological change, and third party energy storage alternatives and other technologies may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities.
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SoCalGas
SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission and storage system that delivers natural gas to a population of, at December 31, 2025, approximately 21.3 million, covering an approximate 24,000 square mile service territory that encompasses Southern California and portions of central California (excluding San Diego County, the City of Long Beach and the desert area of San Bernardino County).
SoCalGas’ assets at December 31, 2025 covered the following territory:
We describe SoCalGas’ natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.” For a discussion of the risks and uncertainties facing SoCalGas’ business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California.”
Sempra California’s Natural Gas Utility Operations
Natural Gas Procurement and Transportation. At December 31, 2025, SoCalGas’ natural gas facilities included 52,765 miles of distribution pipelines, 3,030 miles of transmission and storage pipelines, 48,900 miles of service pipelines and seven transmission compressor stations, and SDG&E’s natural gas facilities consisted of 9,206 miles of distribution pipelines, 177 miles of transmission pipelines, 6,795 miles of service pipelines and one compressor station.
SoCalGas’ and SDG&E’s gas transmission pipelines interconnect with four major interstate pipeline systems: El Paso Natural Gas, Transwestern Pipeline, Kern River Pipeline Company, and Mojave Pipeline Company, allowing customers to bring gas supplies into the SoCalGas gas transmission pipeline system from the various out-of-state gas producing basins. Additionally, an interconnection with PG&E’s intrastate gas transmission pipeline system allows gas to flow into SoCalGas’ gas transmission pipeline system. SoCalGas’ gas transmission pipeline system also has an interconnection with a Mexican gas pipeline company at Otay Mesa on the California/Mexico border that allows gas to not only flow south from the gas producing basins in the southwestern U.S., but to also flow north into SoCalGas’ gas transmission pipeline system from supplies in Mexico. There are also several in-state gas interconnections allowing for delivery of California-produced gas, including a number of direct connections from biomethane producers.
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SoCalGas purchases natural gas under short-term and long-term contracts and on the spot market for SDG&E’s and SoCalGas’ core customers. SoCalGas purchases natural gas from various producing regions, including from Canada, the U.S. Rockies and the southwestern regions of the U.S. Purchases of natural gas are primarily priced based on published indices, which can be subject to volatility. The cost of purchases of natural gas for SDG&E’s and SoCalGas’ core customers is billed to those customers without markup.
To support the delivery of natural gas supplies to its distribution system and to meet the needs of customers, SoCalGas has firm and variable interstate pipeline capacity contracts that require the payment of fixed and variable tariffed and negotiated reservation charges to reserve firm and interruptible transportation rights. Energy companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company and Kern River Gas Transmission Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas.
Natural Gas Storage. SoCalGas owns four natural gas storage facilities with a combined working gas capacity of 137 Bcf and 122 injection, withdrawal and observation wells that provide natural gas storage service. SoCalGas’ and SDG&E’s core customers, along with certain third-party market participants, are allocated a portion of SoCalGas’ storage capacity. SoCalGas uses the remaining storage capacity for load balancing services for all customers and for storage for noncore customers. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility has a storage capacity of 86 Bcf and, subject to a biennial administrative staff review by the CPUC and additional CPUC proceedings, represents 63% of SoCalGas’ working natural gas storage capacity. At December 31, 2025, SoCalGas has been authorized by the CPUC to utilize up to 68.6 Bcf of working gas at the facility.
Customers and Demand. SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers in its territory and SDG&E’s territory on a combined portfolio basis. SoCalGas also offers natural gas transportation and storage services for others.
NATURAL GAS CUSTOMER METERS AND VOLUMES
Customer meter count
Volumes (Bcf) (1)
December 31,
Years ended December 31,
SDG&E:
Residential
Commercial
Electric generation and transportation
Natural gas sales
Transportation
Total
SoCalGas:
Residential
Commercial
Industrial
Electric generation and wholesale
Natural gas sales
Transportation
Total
(1) Includes intercompany sales.
For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers.
Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase their natural gas supplies from producers, marketers or brokers, SoCalGas and SDG&E are obligated to maintain adequate delivery capacity to serve the requirements of all core customers in their service territories.
SoCalGas’ noncore customers consist primarily of electric generation, wholesale, and large commercial and industrial customers. A portion of SoCalGas’ noncore customers are non-end-users, which include wholesale customers consisting primarily of other utilities, including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial customers.
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Noncore customers are responsible for procuring their natural gas requirements, as the regulatory framework does not allow SoCalGas and SDG&E to recover the cost of natural gas procured and delivered to noncore customers.
Natural gas demand largely depends on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preferences, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs, among other factors. Other external factors such as weather, the price of, demand for, and supply sources of electricity, the use and further development of renewable energy sources and energy storage, development of or requirements for new natural gas supply sources, demand for natural gas outside California, storage levels, transport capacity and availability of supply into California and general economic conditions can also result in significant shifts in the market price of natural gas, which may in turn impact demand.
One of the larger drivers of natural gas demand is electric generation. Natural gas-fired electric generation within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western U.S. Natural gas transported for electric generating plant customers may be affected by the overall demand for electricity, growth in self-generation from rooftop solar, the addition of more efficient gas technologies, new energy efficiency initiatives, and the degree to which regulatory changes in electric transmission infrastructure investment divert electric generation from SoCalGas’ and SDG&E’s service areas. The demand for natural gas may also fluctuate due to volatility in the demand for electricity due to seasonality, weather conditions and other impacts, and the availability of competing supplies of electricity, such as renewable energy sources, among other factors. Given the significant level and availability of natural gas-fired generation, we believe natural gas is a dispatchable fuel that can continue to help provide electric reliability in our California service territories.
The natural gas distribution business is subject to seasonality. Demand for natural gas in our service territory typically rises during the winter months to accommodate heating needs and the summer months to support peak electric generation. As is prevalent in the industry, subject to regulatory limitations, SoCalGas typically injects natural gas into storage during the months of April through October and usually withdraws natural gas from storage during the months of November through March.
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Sempra Texas Utilities
Sempra Texas Utilities is comprised of our equity method investments in Oncor Holdings and Sharyland Holdings. Oncor Holdings is a wholly owned entity of Sempra that owns an 80.25% interest in Oncor. TTI owns the remaining 19.75% interest in Oncor. Sempra owns a 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities.
Sempra Texas Utilities’ assets at December 31, 2025 covered the following territory:
For a discussion of the risks and uncertainties related to our equity investments in Oncor Holdings and Sharyland Holdings, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”
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Oncor
Oncor is a regulated electricity transmission and distribution utility that operates in the north-central, eastern, western and panhandle regions of Texas. Oncor delivers electricity to end-use consumers through its electrical systems and also provides transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor’s transmission and distribution assets are located in over 120 counties and more than 400 incorporated municipalities, including the cities of Dallas and Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler, Temple, Killeen and Round Rock, among others. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way pursuant to permits, public utility easements, franchise or other agreements or as otherwise permitted by law.
At December 31, 2025, Oncor had approximately 5,600 employees, including 860 employees covered under a collective bargaining agreement and excluding interns.
Certain ring-fencing measures, governance mechanisms and commitments, which we describe in “Part I – Item 1A. Risk Factors,” are in effect and are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, their owners. Sempra does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning and other important corporate matters and actions, including limited representation on the Oncor Holdings and Oncor boards of directors. Because Oncor Holdings and Oncor are managed independently (i.e., ring-fenced), we account for our 100% ownership interest in Oncor Holdings as an equity method investment.
Electricity Transmission. Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction, maintenance and security of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over its transmission facilities in coordination with ERCOT, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.”
At December 31, 2025, Oncor’s transmission system included approximately 18,418 circuit miles of transmission lines, a total of 1,333 transmission and distribution substations, and interconnection to 230 third-party generation facilities totaling 63,670 MW.
Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to limited interconnections to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above and are collected from load serving entities benefiting from Oncor’s transmission system. Other services offered by Oncor through its transmission business include system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.
Electricity Distribution. Oncor’s electricity distribution business is responsible for the overall safe and reliable operation of distribution facilities, including electricity delivery, power quality, security and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the electricity distribution system within its certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,874 distribution feeders at December 31, 2025.
Oncor’s distribution system included more than 4.1 million points of delivery at December 31, 2025 and consisted of 127,398 circuit miles of overhead and underground lines.
Distribution revenues from residential and small business users are generally based on actual monthly consumption (kWh) and distribution revenues from large commercial and industrial users are based on, depending on size and annual load factor, either actual monthly demand (kW) or the greater of actual monthly demand (kW) or 80% of peak monthly demand during the prior eleven months.
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Customers and Demand. Oncor operates the largest transmission and distribution system in Texas based on the number of end-use customers and miles of transmission and distribution lines. Oncor delivers electricity to more than 4.1 million homes and businesses and operates more than 145,000 circuit miles of transmission and distribution lines as of December 31, 2025 in a territory with an estimated population of approximately 14 million. The majority of consumers of the electricity Oncor delivers are free to choose their electricity supplier from retail electric providers who compete for their business. Oncor is not a seller of electricity, nor does it purchase electricity for resale. Oncor provides wholesale transmission services to its electricity distribution business as well as non-affiliated electricity distribution companies, electric cooperatives and municipally owned utilities. Oncor also provides distribution services, consisting of retail delivery services to retail electric providers that sell electricity to end-use customers, as well as wholesale delivery services to electric cooperatives and municipally owned utilities. At December 31, 2025, Oncor’s distribution business customers primarily consisted of over 100 retail electric providers that sell the electricity it distributes to consumers in its certificated service areas.
Oncor’s revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.
Competition. Oncor operates in certificated areas designated by the PUCT. The majority of Oncor’s service territory is singularly certificated, with Oncor as the only certificated electric transmission and distribution provider. However, in multi-certificated areas of Texas, Oncor competes with certain municipal utilities and rural electric cooperatives for the right to serve end-use customers. In addition, the electric industry is undergoing rapid technological change, and third-party DER (including behind the meter alternatives and private use networks) and virtual power plants and other technologies may increasingly compete with Oncor’s traditional transmission and distribution infrastructure in delivering electricity to consumers.
Sharyland Utilities
Sharyland Utilities is a regulated electric transmission utility that owns and operates, at December 31, 2025, approximately 64 miles of electric transmission lines in south Texas, including a direct current line connecting Mexico and assets in McAllen, Texas. Sharyland Utilities is responsible for providing safe, reliable and efficient transmission and substation services and investing to support infrastructure needs in its service territory, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.” Transmission revenues are provided under tariffs approved by the PUCT.
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Sempra Infrastructure
Our Sempra Infrastructure segment includes the operating companies of our subsidiary, SI Partners, as well as a holding company and certain services companies. SI Partners is included within our Sempra Infrastructure reportable segment but is not the same in its entirety as the reportable segment. Sempra Infrastructure develops, constructs, operates and invests in energy infrastructure to help provide safe, sustainable and reliable access to cleaner energy in markets in the U.S., Mexico and globally.
At December 31, 2025, Sempra Infrastructure owned or held interests in the following assets:
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At December 31, 2025, Sempra, KKR Pinnacle and ADIA each hold a 70%, 20%, and 10% interest, respectively, in SI Partners. SI Partners owns a 100% interest in Sempra LNG Holding, LP and a 99.9% interest in IEnova at December 31, 2025.
The minority partners in SI Partners and Sempra are parties to a limited partnership agreement of SI Partners. Under this agreement, matters are generally decided by majority vote and the managers designated by the partners of SI Partners each vote on an equity-weighted basis based on the ownership percentage of their respective designating limited partner. SI Partners and its controlled subsidiaries are prohibited from taking certain limited actions without the prior written approval of the minority partners. The limited partnership agreement contains certain default remedies if any limited partner fails to fund any amounts required to be funded under the agreement and requires that SI Partners distribute to the limited partners at least 85% of distributable cash of SI Partners and its subsidiaries on a quarterly basis, subject to certain exceptions and reserves. Generally, distributions from SI Partners are made on a pro rata basis. However, KKR Pinnacle is entitled to certain priority distributions in the event of material deviations between certain specified projected cash flows and actual cash flows. Additionally, the minority partners are entitled to certain priority distributions in the event a specified project that reaches a positive FID does not have projected internal rates of return greater than a specified threshold or does not meet certain other conditions by certain dates. If the minority partners approve Sempra’s request that a project not be pursued jointly, or if the minority partners decide not to participate in any proposed project for which Sempra nevertheless desires to make a positive FID, then Sempra may proceed with such project either independently through a different investment vehicle or as a “Sole Risk Project” within SI Partners and receive Sole Risk Interests in respect thereof. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability, and Sempra receives, through the acquisition of Sole Risk Interests, the economic and other benefits, if any, from such projects.
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 the sale to close in the second or third quarter of 2026, subject to closing conditions. Subject to closing, the KKR Partners will own 65% of SI Partners, Sempra will own a 25% interest and ADIA will retain a 10% interest, with the KKR Partners assuming control. Sempra will deconsolidate SI Partners and account for its 25% interest in SI Partners under the equity method within the existing Sempra Infrastructure segment. At closing, we will enter into an amended and restated limited partnership agreement of SI Partners with the KKR Partners and ADIA, which will govern the rights and obligations of the partners with respect to SI Partners after the sale and will include transfer restrictions, provisions for Sole Risk Projects, under which a partner may independently pursue projects at its own cost and risk, and various other provisions. We describe the terms of this post-closing limited partnership agreement in further detail in Note 6 of the Notes to Consolidated Financial Statements.
In December 2025, we entered into an agreement to sell Ecogas, a natural gas regulated distribution utility that we describe below, to Gas Natural del Noroeste S.A. de C.V. for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. We expect to complete the sale in the second or third quarter of 2026, subject to closing conditions.
As a result of satisfying all applicable criteria, we classified SI Partners’ and Ecogas’ assets and liabilities as held for sale and ceased depreciation and amortization. We provide further discussion regarding the sales of SI Partners and Ecogas in Note 6 of the Notes to Consolidated Financial Statements.
Subject to closing these sales, we expect Sempra’s ownership interests in SI Partners and all assets owned by SI Partners, other than those listed in the table below, to be 25% post-closing.
SEMPRA’S OWNERSHIP INTERESTS
At December 31, 2025
Projected post-sale
Cameron LNG Phase 1 facility
Cameron LNG Phase 2 project
ECA LNG Phase 1 project
Ecogas
IMG
PA LNG Phase 1 project
PA LNG Phase 2 project
Sonora pipeline – Guaymas-El Oro segment
TAG Norte
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Sempra Infrastructure consolidates Sempra’s ownership and management of its non-U.S. utility energy infrastructure assets in North America under a single platform. These assets include LNG and natural gas infrastructure in the U.S. and Mexico and renewable energy, LPG and refined products infrastructure in Mexico, which are managed through three business lines: LNG, Energy Networks and Low Carbon Solutions. For a discussion of the risks and uncertainties facing Sempra Infrastructure’s business, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”
LNG
Sempra Infrastructure’s LNG business line is comprised of a natural gas liquefaction and regasification portfolio in development, under construction or in operation and is focused on securely delivering natural gas to markets around the world. Sempra Infrastructure’s development and/or construction of projects, which we describe below, is subject to numerous risks and uncertainties.
Cameron LNG Phase 1 Facility. SI Partners owns 50.2% of Cameron LNG JV. An affiliate of TotalEnergies SE, an affiliate of Mitsui & Co., Ltd., and Japan LNG Investment, LLC (a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha) each own 16.6% of Cameron LNG JV. SI Partners accounts for its ownership interest in Cameron LNG JV under the equity method. No single owner controls or can unilaterally direct significant activities of Cameron LNG JV.
Cameron LNG JV owns and operates the Cameron LNG Phase 1 facility, a natural gas liquefaction, export, regasification and import facility with three natural gas pre-treatment, processing and liquefaction trains. The Cameron LNG Phase 1 facility is located in Hackberry, Louisiana, along the Calcasieu Ship Channel, which handles significant industrial shipping, including large oil and LNG tankers, that we believe is well positioned to supply the Atlantic and Pacific markets. The three liquefaction trains have a combined nameplate capacity of 13.9 Mtpa of LNG with an export capacity of 12 Mtpa of LNG, or approximately 1.7 Bcf of natural gas per day.
The Cameron LNG Phase 1 facility has 20-year liquefaction and regasification tolling capacity agreements in place with affiliates of TotalEnergies SE, Mitsubishi Corporation and Mitsui & Co., Ltd., which collectively subscribe for the full nameplate capacity of the three trains at the facility.
ECA Regas Facility. SI Partners owns and operates the ECA Regas Facility in Baja California, Mexico, which is capable of processing one Bcf of natural gas per day and has a storage capacity of 320,000 cubic meters in two tanks of 160,000 cubic meters each.
The ECA Regas Facility generates revenues from fees under a firm storage and nitrogen injection service agreement with Shell that expires in May 2028 and permits it to use 36% of the terminal’s capacity, with the remaining capacity available for SI Partners’ use. SI Partners uses a portion of its capacity to satisfy its obligation under an LNG SPA with Tangguh PSC through 2029, which we discuss below. ECA LNG Phase 1 will be the sole user of this capacity thereafter.
The land adjacent to and owned by the ECA Regas Facility is the subject of litigation. The facility, however, is not situated on the land that is the subject of this dispute. We discuss litigation, regulatory and other matters that could impact the ECA Regas Facility and the ECA LNG liquefaction projects in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.”
ECA LNG Phase 1 Project. SI Partners owns an 83.4% interest in the ECA LNG Phase 1 project that is under construction. An affiliate of TotalEnergies SE owns the remaining 16.6% interest in the project. The ECA LNG Phase 1 project will consist of a one-train natural gas liquefaction facility at the site of SI Partners’ existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa.
The ECA LNG Phase 1 project has definitive 20-year SPAs with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG and with Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG. The customers have a termination right if the ECA LNG Phase 1 project does not commence commercial operations under the SPAs by February 24, 2026, subject to certain additional conditions, for which we have requested an extension. As of February 26, 2026, no customers have given notice of their intent to terminate the SPAs.
The ECA LNG Phase 1 project achieved mechanical completion in December 2025, and we expect the project to produce LNG cargoes for sale in the spring of 2026 and sales under the long-term SPAs to begin shortly after substantial completion when the facility commences commercial operations, which is targeted in the summer of 2026. Reaching substantial completion under the EPC contract is subject to various milestones, including achieving certain performance tests and functionality.
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PA LNG Phase 1 Project. SI Partners, KKR Denali and an affiliate of ConocoPhillips own a 28%, 42% and 30% interest, respectively, in the PA LNG Phase 1 project under construction on a greenfield site in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. The PA LNG Phase 1 project will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa.
The PA LNG Phase 1 project has definitive SPAs for LNG offtake with:
▪ an affiliate of ConocoPhillips for a 20-year term for 5 Mtpa of LNG, as well as a natural gas supply management agreement whereby an affiliate of ConocoPhillips will manage the feed gas supply requirements for the PA LNG Phase 1 project
▪ RWE Supply & Trading GmbH, a subsidiary of RWE AG, for a 15-year term for 2.25 Mtpa of LNG
▪ INEOS Energy Trading Limited, a subsidiary of INEOS Limited, for a 20-year term for approximately 1.4 Mtpa of LNG
▪ Polski Koncern Naftowy Orlen S.A. for a 20-year term for approximately 1 Mtpa of LNG
▪ ENGIE S.A. for a 15-year term for approximately 0.875 Mtpa of LNG
The first train of the Port Arthur LNG liquefaction project remains on schedule, and we continue to expect the first and second trains to commence commercial operations at or near the end of 2027 and in 2028, respectively.
KKR Denali’s interest in the PA LNG Phase 1 project is governed by a limited liability company agreement under which (i) a subsidiary of SI Partners (a) is the managing member, (b) exclusively holds the right to make decisions with respect to certain expansions, such as the PA LNG Phase 2 project, (c) has certain rights to preferential distributions from specified revenues and expansion true-up payments, and (d) through a parent entity that is a subsidiary of Sempra, bears a disproportionately higher allocation of certain capital contribution commitments in certain budgetary overrun scenarios; and (ii) KKR Denali has certain investor protection voting rights.
PA LNG Phase 2 Project. Since September 2025, SI Partners owns 50.1% and Blackstone owns 49.9% of the PA LNG Phase 2 project, a large-scale natural gas liquefaction project located adjacent to the PA LNG Phase 1 project. As we discuss in Note 12 of the Notes to Consolidated Financial Statements, Blackstone’s equity interest is subject to redemption and exit rights that are outside the control of SI Partners and Blackstone. As a result, we account for Blackstone’s NCI as being contingently redeemable, which is presented as CRNCI in Sempra’s Consolidated Balance Sheet.
Construction of the PA LNG Phase 2 project commenced in September 2025 after reaching a positive FID. The PA LNG Phase 2 project will include two liquefaction trains, one LNG storage tank, and associated facilities with a nameplate capacity of approximately 13 Mtpa.
The PA LNG Phase 2 project has definitive SPAs for LNG offtake with:
▪ ConocoPhillips for a 20-year term for 4 Mtpa of LNG on a free-on-board basis
▪ EQT Corporation for a 20-year term for 2 Mtpa of LNG on a free-on-board basis
▪ JERA Co. Inc. for a 20-year term for 1.5 Mtpa of LNG on a free-on-board basis
In addition, SI Partners has a definitive SPA with the PA LNG Phase 2 project for a 20-year term for 2.5 Mtpa of LNG and has entered into offtake agreements for excess quantities of LNG, including an offtake agreement for a 30-year term to the extent of incremental amounts produced above 10 Mtpa up to an additional 0.75 Mtpa.
We expect the third and fourth trains of the Port Arthur LNG liquefaction project to commence commercial operations in 2030 and 2031, respectively.
Asset and Supply Optimization. SI Partners has an LNG SPA through 2029 with Tangguh PSC for the supply of the equivalent of 500 MMcf of natural gas per day at a price based on the SoCal Border index for natural gas. The LNG SPA allows Tangguh PSC to divert certain LNG volumes to other global markets in exchange for payments of diversion fees. SI Partners may also enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the ECA Regas Facility for sale to other parties. SI Partners uses the natural gas produced from this LNG to supply a contract for the sale of natural gas to the CFE at prices that are based on the SoCal Border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, SI Partners may purchase natural gas in the market to satisfy such commitment.
SI Partners purchases, transports and sells natural gas and LNG, and has customers in both the U.S. and Mexico, including the CFE. SI Partners may also purchase natural gas from other Sempra affiliates. Natural gas purchases and transportation arrangements are substantially backed by long-term, U.S. dollar-based contracts for the sale of natural gas to third parties (both U.S. sourced and derived from imported LNG), LNG offtake and natural gas storage and pipeline capacity.
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LNG Projects Under Development. SI Partners is pursuing or evaluating the following development opportunities:
▪ Cameron LNG Phase 2 project, an expansion of the Cameron LNG Phase 1 facility that would add one electric drive liquefaction train and debottlenecking capacity from the existing three trains
▪ ECA LNG Phase 2 project, a large-scale natural gas liquefaction project to be located at the site of SI Partners’ existing ECA Regas Facility in Baja California, Mexico
No FID has been reached for either of these potential projects.
Demand and Competition. North America benefits from numerous competitive advantages as a supplier of LNG to world markets, including the following:
▪ high levels of developed and undeveloped natural gas resources, including unconventional natural gas and oil relative to domestic consumption levels
▪ flexible and mature oil and gas markets resulting in efficient unit costs of gas production
▪ availability of extensive natural gas pipeline transmission systems and natural gas storage capacity with proximity to production locations
Global LNG demand and competition may limit North American LNG exports, as international liquefaction projects attempt to match North American LNG production costs and customer contractual rights such as volume and destination flexibility. North American LNG exports add market flexibility that is expected to facilitate additional growth of a global commodity market for natural gas and LNG.
Our LNG projects in development, under construction or in operation all compete globally to market and sell LNG to remarketers and end-users, including gas and electric utilities located in LNG-importing countries around the world. We compete with liquefaction projects currently operating and those under development in the global LNG market. In addition to the U.S., these competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe.
Energy Networks
Sempra Infrastructure’s Energy Networks business line is comprised of a natural gas transportation and distribution network.
Cross-Border Interconnections and In-Country Pipelines. SI Partners develops, constructs, owns and operates systems for the receipt, transportation, compression and delivery of natural gas and ethane. At December 31, 2025, these systems consisted of 1,985 miles of natural gas transmission pipelines, 17 natural gas compression stations and 139 miles of ethane pipelines in Mexico. The design capacity of these pipeline assets is over 16,900 MMcf per day of natural gas, 204 MMcf per day of ethane gas and 106,000 barrels per day of ethane liquid. Capacity on SI Partners’ pipelines and related assets is substantially contracted under long-term, U.S. dollar-based agreements with major industry participants such as the CFE, Centro Nacional de Control de Gas, PEMEX and other similar counterparties. See “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure” for a discussion about the Guaymas-El Oro segment of the Sonora pipeline.
SI Partners owns the Cameron Interstate Pipeline, a 40-mile natural gas pipeline in south Louisiana that links the Cameron LNG Phase 1 facility in Cameron Parish in Louisiana to seven pipelines that offer access to major feed gas supply basins in Texas and the northeast, midcontinent and southeast regions of the U.S. The majority of transportation capacity on the Cameron Interstate Pipeline is under long-term transportation service agreements with shippers for delivery to the Cameron LNG Phase 1 facility.
SI Partners is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana. We expect the Port Arthur Pipeline Louisiana Connector to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements.
Natural Gas Distribution. SI Partners owns the natural gas distribution regulated utility, Ecogas, which operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. At December 31, 2025, Ecogas had approximately 3,246 miles of distribution pipeline, and approximately 169,000 customer meters serving more than 661,000 residential, commercial and industrial consumers with total distribution volume of 94.1 MMcf per day in 2025, of which 10.7 MMcf per day were gas sales to direct end users of Ecogas. Ecogas relies on supply and transportation services, including from SI Partners and SoCalGas for the natural gas it distributes to its customers.
As we discuss in Note 6 of the Notes to Consolidated Financial Statements, in December 2025, we entered into an agreement to sell Ecogas to Gas Natural del Noroeste S.A. de C.V. for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. We expect to complete the sale in the second or third quarter of 2026, subject to closing conditions.
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LPG Storage and Associated Systems. SI Partners owns and operates the TDF, S. de R. L. de C. V. (TDF) pipeline system and the Guadalajara LPG terminal. At December 31, 2025, the TDF pipeline system consisted of approximately 118 miles of 12-inch diameter LPG pipeline with a design capacity of 34,000 barrels per day and associated storage and dispatch facilities. The TDF pipeline system runs from PEMEX’s Burgos facility in the Mexican state of Tamaulipas, Mexico to SI Partners’ approximately 32,000-barrel LPG storage facility near the city of Monterrey, Mexico and is fully contracted to PEMEX on a firm basis through 2027. SI Partners’ Guadalajara LPG terminal is an 80,000-barrel LPG storage facility near Guadalajara, Mexico, with associated loading and dispatch facilities, and serves the LPG needs of Guadalajara. The Guadalajara LPG terminal is fully contracted to PEMEX on a firm basis through 2028. Both contracts are U.S. dollar-denominated or referenced and are periodically adjusted for inflation.
Refined Products and Natural Gas Storage. SI Partners’ refined products storage business develops, constructs, owns and operates systems for the receipt, storage and delivery of refined products, principally gasoline, diesel and jet fuel, throughout the Mexican states of Baja California, Colima, Estado de Mexico, Puebla, Sinaloa and Veracruz for private companies, with a combined storage capacity of 4.6 million barrels fully operating as of December 31, 2025. Our customer contracts for our refined products storage business are structured as long-term, U.S. dollar-denominated, firm capacity storage agreements with counterparties including Marathon Petroleum Corporation, Valero Energy Corporation and PEMEX. The contracted rate under these contracts is independent from each terminal’s regulated rate as determined by the CNE.
SI Partners is constructing Louisiana Storage, a 12.5-Bcf salt dome natural gas storage facility to support the PA LNG Phase 1 project. The construction includes an 11-mile pipeline that will connect to the Port Arthur Pipeline Louisiana Connector. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project.
Demand and Competition. Ecogas faces competition from other distributors of natural gas in each of its three distribution zones as other distributors of natural gas construct or consider constructing natural gas distribution systems. SI Partners’ pipeline and storage facilities businesses compete with other regulated and unregulated pipeline and storage facilities. They compete primarily on the basis of price (in terms of storage and transportation fees), available capacity and interconnections to downstream markets. The overall demand for natural gas distribution services increases during the winter months, while the overall demand for power increases during the summer months.
Low Carbon Solutions
Sempra Infrastructure’s Low Carbon Solutions business line is focused on developing, constructing and operating energy infrastructure to help meet the demand for lower carbon and reliable energy supply. The portfolio of infrastructure assets includes renewable energy generation, a natural gas-fired power plant, as well as the development of infrastructure for carbon capture and storage and for generation and storage of low carbon energy.
Renewable Power Generation. SI Partners develops, constructs, owns and operates renewable energy generation facilities that have long-term PPAs to sell the electricity they generate to their customers, which are generally load-serving entities and industrial and other customers. Load serving entities sell electric service to their end-users and wholesale customers upon receipt of power delivery from these energy generation facilities, while industrial and other customers consume the electricity to run their facilities. At December 31, 2025, SI Partners had total nameplate capacity of 1,044 MW related to its operating wind and solar power generation facilities. Generation from SI Partners’ renewable energy assets is susceptible to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight. Some of these facilities may be affected by recent legal and regulatory changes in Mexico, which we discuss in “Part I – Item 1A. Risk Factors.”
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RENEWABLE POWER GENERATION
Location
Contract expiration date
Nameplate capacity (MW)
Wind power generation facilities:
ESJ – first phase
Tecate, Baja California
ESJ – second phase
Tecate, Baja California
Ventika
Nuevo León, Mexico
Solar power generation facilities:
Border Solar
Ciudad Juarez, Chihuahua
2035, 2040 and 2041
Don Diego Solar
Benjamin Hill, Sonora
2037 and 2040
Pima Solar
Caborca, Sonora
Rumorosa Solar
Tecate, Baja California
2034 and 2039
Tepezalá Solar
Aguascalientes, Mexico
2035 and 2040
Total
Natural Gas-Fired Generation. SI Partners owns and operates the TdM power plant in the vicinity of Mexicali, Baja California, adjacent to the Mexico-U.S. border. TdM is a 625 MW natural gas-fired, combined-cycle power plant that is connected to our Gasoducto Rosarito pipeline system, which enables it to receive regasified LNG from the ECA Regas Facility as well as continental gas supplied from the U.S. on the North Baja pipeline. TdM generates revenue from selling electricity and resource adequacy to the California ISO for delivery to governmental, public utility and wholesale power marketing entities.
Low Carbon Solutions Projects. The Cimarrón Wind project, an approximately 320-MW wind generation facility in Baja California, Mexico, commenced energy generation in October 2025 during its commissioning phase. We expect commercial operations to commence in the first quarter of 2026. SI Partners has a 20-year PPA with Silicon Valley Power for the long-term supply of renewable energy to the City of Santa Clara, California. Cimarrón Wind will utilize the available capacity on one of SI Partners’ existing cross-border high voltage transmission lines to interconnect and deliver clean energy to the East County substation in San Diego County.
SI Partners is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana, together with TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation. This proposed project is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility, the proposed Cameron LNG Phase 2 project and potentially other sources.
Demand and Competition. SI Partners competes with Mexican and foreign companies for new energy infrastructure projects in Mexico. Some of its competitors (including public or state-operated companies and their affiliates) may have better access to capital or greater financial and other resources or advantages, including those provided by recent legal and regulatory changes in Mexico, which could give them a competitive advantage for such projects.
SI Partners sells power from its ESJ wind power generation facilities into California, where renewable energy demand is affected by U.S. state mandates requiring a portion of energy to come from renewable sources. These mandates are part of California’s RPS Program. The first and second phases of ESJ, which are in operation, were certified by the CEC under the RPS Program. Certification by the CEC means that the energy produced by a facility is eligible to generate RECs, which can be used to meet California’s RPS Program requirements, which in turn influences the demand from California load serving entities for energy from that facility. In January 2025, the CEC approved Cimarrón Wind’s application for precertification under the RPS Program.
TdM participates in the day-ahead and real-time markets supplying power into the California electricity system. SI Partners manages commodity price risk at TdM through a mix of day-ahead sales of energy, energy spreads hedging, ancillary services, and short-term to medium-term capacity sales.
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REGULATION
We discuss the material effects of compliance with government regulations, including environmental regulations, on our capital expenditures, earnings and competitive position in “Part II – Item 7. MD&A” and Note 16 of the Notes to Consolidated Financial Statements.
Utility Regulation
California
SDG&E and SoCalGas are principally regulated at the state level by the CPUC, CEC and CARB.
The CPUC:
▪ consists of five commissioners appointed by the Governor of California for staggered, six-year terms;
▪ regulates, among other things, SDG&E’s and SoCalGas’ customer rates and conditions of service, sales of securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters, except as described below in “U.S. Federal;”
▪ has jurisdiction over the proposed construction of major electric generation, transmission and distribution, and natural gas transmission, distribution and storage facilities in California;
▪ conducts reviews and audits of utility performance and compliance with regulatory guidelines and conducts investigations related to various matters, such as safety standards and practices, reliability and planning, deregulation, competition, disconnection and billing practices, commodity pricing, resource adequacy and environmental compliance; and
▪ regulates the interactions and transactions of SDG&E and SoCalGas with Sempra and other affiliates, including their marketing functions.
The CPUC also oversees and regulates other energy-related products and services, including solar and wind energy, bioenergy, alternative energy storage and other forms of renewable energy. In addition, the CPUC’s safety and enforcement authority includes inspections, investigations and citation and enforcement programs for safety and other violations.
The CEC publishes electric demand forecasts for the state and specific service territories. Based on these forecasts, the CEC:
▪ determines the need for additional energy sources and conservation programs;
▪ sponsors alternative-energy research and development projects;
▪ promotes energy conservation programs to reduce demand for natural gas and electricity within California;
▪ maintains a statewide plan of action in case of energy shortages; and
▪ certifies power-plant sites and related facilities within California.
The CEC conducts a 20-year forecast of available supplies and prices for every market sector that consumes natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and transportation and distribution costs. This analysis is one of many resource materials used to support SDG&E’s and SoCalGas’ long-term investment decisions.
We discuss regulatory oversight by CARB below in “Environmental Matters – Air Quality and GHG Emissions.”
Texas
Oncor’s and Sharyland Utilities’ rates are regulated at the state level by the PUCT and, in the case of Oncor, at the city level by certain cities. The PUCT has original jurisdiction over wholesale transmission rates and services and retail rates and services in unincorporated areas and in municipalities that have ceded original jurisdiction to the PUCT, and has exclusive appellate jurisdiction to review the retail rates, retail services, and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that do not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).
At the state level, PURA requires utility owners or operators of electric transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state’s open-access requirements for all utilities that are subject to the PUCT’s jurisdiction over electric transmission services, including Oncor.
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U.S. Federal
SDG&E and SoCalGas are also regulated at the federal level by the FERC, EPA, DOE and DOT, and for SDG&E the NRC.
The FERC regulates SDG&E’s and SoCalGas’ interstate sale and transportation of natural gas. The FERC also regulates SDG&E’s:
▪ electric transmission rates
▪ transmission and wholesale sales of electricity in interstate commerce
▪ transmission access
▪ rates of return and rates of depreciation on electric transmission investments
▪ electric rates involving sales for resale
▪ the application of the uniform system of accounts
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. The U.S. Energy Policy Act governs procedures for requests for electric transmission service. To a small degree related to limited interconnections to other markets, Oncor’s electric transmission revenues are provided under tariffs approved by the FERC.
The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities in the U.S., including SONGS, in which SDG&E owns a 20% interest and which permanently ceased operations in 2013. The NRC and various state regulations require extensive review of these facilities’ safety, radiological and environmental aspects. We provide further discussion of SONGS matters, including the closure and decommissioning of the facility, in Note 15 of the Notes to Consolidated Financial Statements.
The EPA implements federal laws to protect human health and the environment, including federal laws on air quality, water quality, wastewater discharge, solid waste management, and hazardous waste disposal and remediation. The EPA also sets national environmental standards that state and tribal governments implement through their regulations. As a result, SDG&E, SoCalGas, Oncor and Sharyland Utilities are subject to an interrelated framework of environmental laws and regulations.
The DOT, through PHMSA, has established regulations regarding engineering standards and operating procedures, including procedures intended to manage cybersecurity risks, applicable to SDG&E’s and SoCalGas’ natural gas transmission and distribution pipelines, as well as natural gas storage facilities. The DOT has certified the CPUC to administer oversight of and compliance with these regulations for the entities they regulate in California.
California ISO Market
The California IOUs’ electric transmission facilities are under the operational control of the California ISO. The California ISO is a non‑profit, federally regulated organization that manages the flow of electricity from generators to local utilities across approximately 80% of California’s high‑voltage power grid. Within its balancing authority area, the California ISO oversees the markets that help balance electricity supply and demand, coordinate dispatch of generation, and manage system constraints.
ERCOT Market
As member utilities, Oncor and Sharyland Utilities operate within the ERCOT market, which represents approximately 90% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the ISO of the interconnected transmission grid for those systems. ERCOT is subject to oversight by the PUCT and the Texas Legislature. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants, in the ERCOT region. ERCOT’s membership consists of corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers, distribution service providers, independent retail electric providers and consumers.
The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected electric transmission grid. Oncor and Sharyland Utilities, along with other owners of electric transmission and distribution facilities in Texas, assist the ERCOT ISO in its operations. Each of these Texas utilities has planning, design, construction, operation, maintenance and security responsibility for the portion of the transmission grid and the load-serving substations it owns, primarily within its certificated service area. Each participates with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove any existing constraints and interconnect energy generation on the ERCOT transmission grid. These transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.
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Oncor and Sharyland Utilities are subject to reliability standards adopted and enforced by the Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with the standards of the North American Electric Reliability Corporation, including critical infrastructure protection, and ERCOT protocols.
Other U.S. State and Local Territories Regulation
SDG&E has electric franchise agreements with the two counties and the 27 cities in its electric service territory, and natural gas franchise agreements with the one county and the 18 cities in its natural gas service territory. These franchise agreements allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of electricity or natural gas. Most of the franchise agreements have no expiration dates, while some have expiration dates that range from 2028 to 2041. SDG&E has electric and natural gas franchises for the City of San Diego. These franchise agreements, which went into effect in July 2021, provide SDG&E the opportunity to serve the City of San Diego for 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewal. These franchise agreements have been challenged in a lawsuit that we discuss in Note 16 of the Notes to Consolidated Financial Statements.
SoCalGas has natural gas franchise agreements with the 12 counties and the 232 cities in its service territory. These franchise agreements allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the franchise agreements have no expiration dates, while some have expiration dates that range from 2026 to 2069.
Other U.S. Federal Regulation
The FERC regulates certain of SI Partners’ assets pursuant to the U.S. Federal Power Act and Natural Gas Act, which provide for FERC jurisdiction over, among other things, sales of wholesale power in interstate commerce, transportation of natural gas in interstate commerce, and siting and permitting of LNG facilities.
The FERC may regulate rates and terms of service based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be sufficiently competitive, rates may be market-based. FERC-regulated rates at SI Partners are market-based for wholesale electricity sales, cost-based for the transportation of natural gas, and market-based for the purchase and sale of LNG and natural gas.
SI Partners’ investment in Cameron LNG JV and its LNG projects under construction are subject to regulations of the DOE regarding the export of LNG. Under these regulations, the DOE acts on LNG export applications to non-FTA countries after completing a public interest review that includes several criteria, including economic and environmental review of the proposed export. SI Partners’ natural gas liquefaction projects under development are subject to similar regulations.
SDG&E, SoCalGas and certain of SI Partners’ businesses are subject to the DOT rules and regulations regarding pipeline safety. PHMSA, acting through the Office of Pipeline Safety, is responsible for administering the DOT’s national regulatory program to help ensure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines, including pipelines associated with natural gas storage, and develops regulations and other approaches to risk management to help ensure safety in design, construction, testing, operation, maintenance and emergency response of pipeline facilities. PHMSA also regulates the safety of onshore LNG facilities.
SDG&E, SoCalGas and SI Partners are also subject to regulation by the U.S. Commodity Futures Trading Commission.
Foreign Regulation
Operations and projects in our Sempra Infrastructure segment are subject to regulation by the ASEA, CNE, SENER, the Mexican Ministry of Environment and Natural Resources of Mexico (Secretaría del Medio Ambiente y Recursos Naturales), and other labor and environmental agencies of city, state and federal governments in Mexico. New energy infrastructure projects may also require a favorable opinion from Mexico’s Competition Commission (Comisión Federal de Competencia Económica) in order to be constructed and operated. Recent legal and regulatory changes in Mexico, which we discuss in “Part I – Item 1A. Risk Factors,” are designed to increase the government’s control and participation in the energy sector.
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Licenses and Permits
Our utilities in California and Texas obtain numerous permits, authorizations and licenses for, as applicable, the transmission and distribution of natural gas and electricity and the operation and construction of related assets, including electric generation and natural gas storage facilities, some of which require periodic renewal.
SI Partners obtains numerous permits, authorizations and licenses for its electric and natural gas distribution, generation and transmission systems from the local governments where these services are provided. The permits for generation, transportation, storage and distribution operations at SI Partners are generally for 30-year terms, with options for renewal under certain regulatory conditions.
SI Partners obtains permits, authorizations and licenses for the construction and operation of:
▪ LNG facilities, including the expansion thereof, and for the import and export of LNG and natural gas
▪ facilities for the receipt, storage and delivery of refined products
▪ natural gas storage facilities and pipelines
SI Partners’ businesses also obtain permits, authorizations and licenses in connection with their participation in the wholesale electricity market.
Most of the permits and licenses associated with SI Partners’ construction and operations are for periods generally in alignment with the construction cycle or expected useful life of the asset and in some cases are greater than 20 years.
RATEMAKING MECHANISMS
Sempra California
General Rate Case Proceedings
A CPUC GRC proceeding is designed to set authorized base revenue requirements that are sufficient to allow SDG&E and SoCalGas to recover their reasonable forecasted operating costs and to provide the opportunity to realize their authorized rates of return on their investments. The proceeding generally establishes the test year revenue requirements and provides for attrition, or annual increases in revenue requirements, for each year following the test year. Both the test year revenue requirements and attrition authorize how much SDG&E and SoCalGas can collect from their customers in base rates.
We discuss SDG&E’s and SoCalGas’ most recent GRCs in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.
Cost of Capital Proceedings
A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and return on rate base, which is a weighted average of the authorized returns on debt, preferred equity and common equity (referred to as ROE), weighted on a basis consistent with the authorized capital structure. The authorized return on rate base approved by the CPUC is the rate that SDG&E and SoCalGas use to establish customer rates to finance investments in CPUC-regulated electric distribution and generation, natural gas distribution, transmission and storage assets, as well as general PP&E and information technology systems investments to support operations.
The CPUC established the CCM to apply in the interim years between required cost of capital applications. The CCM considers changes in the cost of capital using changes in interest rates as reflected by the applicable utility bond index published by Moody’s (CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). The index applicable to SDG&E and SoCalGas is based on each utility’s credit rating. The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered in each measurement period, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus 1.00% for the measurement period. Subject to regulatory approval, the CCM, if triggered, would automatically update the authorized cost of debt based on actual costs and update the authorized ROE upward or downward by 20% of the difference between the CCM benchmark rate and the applicable Moody’s utility bond index during the measurement period. Alternatively, each of SDG&E and SoCalGas is permitted to file a cost of capital application to have its cost of capital determined in lieu of the CCM in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market.
We discuss the cost of capital and CCM in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.
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Transmission Rate Cases
SDG&E files separate rate cases with the FERC for its FERC-regulated electric transmission operations and assets. The proceeding establishes, among other things, a ROE, capital structure and a formulaic rate whereby rates are determined using (i) a base period of historical costs and a forecast of capital investments, and (ii) a true-up period, similar to balancing account treatment, that is designed to provide earnings equal to SDG&E’s actual cost of service including its authorized return. SDG&E makes annual filings with the FERC to update rates for the following calendar year based on inputs in the FERC-approved formula rate that are contained in SDG&E’s Transmission Owner Tariff. SDG&E may also file for ROE incentives that might apply under FERC rules.
We discuss the latest FERC rate matters in “Part I – Item 1A. Risk Factors,” “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra California” and Note 4 of the Notes to Consolidated Financial Statements.
Incentive Mechanisms
SoCalGas is subject to the GCIM and is eligible for financial awards or subject to financial penalties depending on its performance in relation to specific benchmarks. We discuss the GCIM in “Part II – Item 7. MD&A” and Note 3 of the Notes to Consolidated Financial Statements.
Other Cost-Based Regulatory Recovery
The CPUC, and the FERC as applicable to SDG&E, authorize SDG&E and SoCalGas to collect, or in the case of CPUC programmatic activities, to apply for, additional revenue requirements beyond base rates from customers for certain operating and capital-related costs (depreciation, taxes and return on rate base), including for:
▪ costs to purchase natural gas and electricity
▪ costs associated with administering public purpose, demand response, environmental compliance, and customer energy efficiency programs
▪ programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation
▪ costs associated with third-party liability insurance premiums
Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded in a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met when the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may require regulatory review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including reviews of costs for reasonableness, and may impose limitations on a program’s total cost or revenue requirement. These procedures and requirements could result in delays or disallowances of recovery from customers.
Sempra Texas Utilities
Rates and Cost Recovery
Oncor’s and Sharyland Utilities’ rates are each regulated at the state level by the PUCT and, in the case of Oncor, at the city level by certain cities, and are subject to regulatory rate-setting processes and earnings oversight. This regulatory treatment does not provide assurance as to achievement of earnings levels or recovery of actual costs. Instead, rates are based on an analysis of each utility’s costs and capital structure in a designated test year, as reviewed and approved in regulatory proceedings. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. However, there is no assurance that the PUCT will judge all of the Texas utilities’ costs to have been prudently incurred and therefore fully recoverable. The approved levels and timing of recovery could differ significantly from requested levels and timing. There can also be no assurance that the PUCT will approve any other items requested in any rate proceeding or that the regulatory process in which rates are determined will result in rates that produce full recovery of the Texas utilities’ actual post-test year costs and/or the full return on invested capital allowed by the PUCT, particularly during periods of increased capital spending, high inflation or increases in interest rates resulting in increased costs relative to the utility’s most recent base rate review.
PUCT rules provide that a transmission and distribution utility must file a comprehensive base rate review within four years of the last order in its most recent comprehensive rate proceeding unless an extension is approved by the PUCT. However, the PUCT or any city retaining original jurisdiction over rates may direct the utility to file a base rate review, or the utility may voluntarily file a base rate review, any time prior to that deadline.
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In addition, PUCT rules allow for interim rate adjustments known as capital trackers that allow Texas electric utilities to recover, subject to reconciliation, the cost of certain investments before a comprehensive base rate review. As a result of Texas legislation signed into law in 2025 establishing the UTM, qualifying electric utilities like Oncor can apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments, as an alternative to separate distribution cost recovery factor and transmission cost of service capital tracker filings. All investments included in a capital tracker update filing are ultimately subject to prudence review by the PUCT in the next base rate review after such assets are put into service. Oncor anticipates filing its initial UTM application on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result, Oncor has recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. We discuss Oncor’s anticipated first UTM filing in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”
Capital Structure and Return on Equity
In April 2023, the PUCT issued a final order in a comprehensive base rate review that set Oncor’s authorized regulatory capital structure ratio at 57.5% debt to 42.5% equity, its authorized ROE at 9.70%, and its authorized cost of debt at 4.39%. We discuss Oncor’s most recent comprehensive base rate proceeding and a settlement request that, with PUCT approval, would change Oncor’s capital structure, authorized ROE and authorized cost of debt in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Texas Utilities.”
In November 2025, the PUCT approved Sharyland Utilities’ total revenue requirement at $53 million, with a capital structure ratio of 59% debt to 41% equity, an ROE of 9.60%, and a long-term cost of debt of 4.52%.
Sempra Infrastructure
Ecogas’ revenues are derived from service and distribution fees charged to its customers in Mexican pesos. The price Ecogas pays to purchase natural gas, which is based on international price indices, is passed through directly to its customers. The service and distribution fees charged by Ecogas are regulated by the CNE, which performs a review of rates every five years and monitors prices charged to end-users. Ecogas’ rate case for 2021 through 2025 was approved by the CNE in December 2023. The tariffs operate under a return-on-asset-base model. In the annual tariff adjustment, rates are adjusted to account for inflation or fluctuations in exchange rates, and inflation indexing includes separate U.S. and Mexican cost components so that U.S. costs can be included in the final distribution rates.
ENVIRONMENTAL MATTERS
We discuss environmental issues affecting us in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.” You should read the following additional information in conjunction with those discussions.
Hazardous Substances
The CPUC’s Hazardous Waste Collaborative mechanism allows California’s IOUs to recover hazardous waste cleanup costs for certain sites, including those related to certain Superfund sites. For sites that are covered by this mechanism, SDG&E and SoCalGas are permitted to recover in rates 90% of hazardous waste cleanup costs and related third-party litigation costs, and 70% of related insurance-litigation expenses. In addition, SDG&E and SoCalGas can retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates.
We record estimated liabilities for environmental remediation when amounts are probable and estimable. In addition, we record amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism as regulatory assets.
Air Quality and GHG Emissions
The natural gas and electric industries are subject to increasingly stringent air quality and GHG emissions standards. Our operations in California are subject to the requirements described below, and our operations in other locations may be subject to laws and regulations in applicable jurisdictions governing similar topics, including GHG emissions reduction objectives, GHG emissions reporting standards and carbon taxes in certain states. AB 32, the California Global Warming Solutions Act of 2006, assigns responsibility to CARB for monitoring and establishing policies for reducing GHG emissions. The law requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable, and cost-effective GHG emissions reductions, including a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a department within the California Environmental Protection Agency, an organization that reports directly to the Governor’s Office. SI Partners is also subject to the rules and regulations of CARB.
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California requires certain electric retail sellers, including SDG&E, to deliver a significant percentage of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by the CPUC and the CEC, are generally known as the RPS Program. SB 100 (enacted in 2018) and SB 1020 (enacted in 2022) require each California electric utility, including SDG&E, to procure at least 50% of its annual retail electricity delivered from renewable energy or zero-carbon sources by the end of 2026, 60% by the end of 2030, 90% by the end of 2035, 95% by the end of 2040, and 100% by the end of 2045. SDG&E expects to be in compliance with these RPS program requirements. State law also requires California’s retail electricity supply to be met with a mix of RPS Program-eligible and zero-carbon sources by 2045 without increasing carbon emissions elsewhere in the western grid or allowing resource shuffling, and instructs the CPUC, CEC, CARB and other state agencies to incorporate this requirement into all relevant planning. In addition, AB 1279 (enacted in 2022) requires the State of California to achieve net-zero GHG emissions no later than 2045, and to achieve and maintain net negative GHG emissions thereafter. AB 1279 also directs CARB to address this goal in future scoping plans, which affect major sectors of California’s economy, including energy utilities, transportation, agriculture, construction and manufacturing. Other state climate initiatives in line with this statewide goal include executive orders requiring sales of all passenger vehicles, including SDG&E’s and SoCalGas’ light-duty fleet vehicles, to be zero-emission by 2035. In 2025, the U.S. Administration rescinded the Clean Air Act waiver on which California’s zero-emission vehicle mandate is based, rendering the mandate unenforceable pending the resolution of related litigation.
California has implemented a biomethane procurement program, whereby IOUs providing gas service in California will procure a portion of the natural gas they deliver from CPUC-approved sources of biomethane. The program establishes a Renewable Gas Standard for biomethane procurement that will be phased in through the end of 2030. The CPUC is currently reviewing IOUs’ renewable gas procurement plans and related public comments and considering potential enhancements to the program structure to increase market competition and reduce entry barriers for biomethane producers.
SDG&E and SoCalGas generally recover the costs to comply with these standards in rates. We discuss GHG emissions standards, allowances and obligations and RECs in Note 1 of the Notes to Consolidated Financial Statements.
The South Coast Air Quality Management District is the air pollution control agency responsible for regulating stationary sources of air pollution in the South Coast Air Basin in Southern California. The district’s territory covers all of Orange County and the urban portions of Los Angeles, San Bernardino and Riverside counties.
Sempra aims to have net-zero scope 1 and 2 GHG emissions by 2050 and has an interim aim of 50% scope 1 and 2 GHG emissions reductions by 2035 (this interim target is relative to a 2019 baseline, applies to Sempra California’s operations and Sempra Infrastructure’s Mexico (non-LNG) operations, and may be subject to further revision if Sempra’s planned sale of a portion of its equity interest in SI Partners is completed). Sempra and its subsidiaries also continue to advocate for programs and initiatives that support regulatory, consumer and market demand for lower- and zero-carbon energy. Additionally, although SDG&E and SoCalGas continue to align with California’s goal to achieve net-zero GHG emissions by 2045, their respective abilities to achieve their net-zero aspirations, as well as Sempra’s ability to achieve its 2035 and 2050 aims and meet the demand for lower-carbon and reliable energy in California and elsewhere, will depend on the development, commercialization and regulatory acceptance of affordable, alternative and lower-carbon energy sources, including cleaner fuels, among other factors. For a discussion of risks and uncertainties related to our net-zero and other climate aims, see “Part I – Item 1A. Risk Factors.”
With respect to our net-zero aims, even in a state of “net-zero,” GHG emissions may still be generated, but innovation and continued development of new technology and solutions could allow an equal amount of carbon dioxide or its equivalent to be removed from the atmosphere, resulting in a zero net increase in emissions. In addition, for purposes of these net-zero aims, we expect that achievement of net-zero GHG emissions will be determined based on operations at the time the applicable goal is to be reached, and GHG emissions will be calculated according to widely accepted emissions reporting guidelines or mandates at that time. Our net-zero aim does not include Oncor, which sets its own goals due to certain ring-fencing measures that limit Sempra’s ability to direct the management, policies and operations of Oncor.
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OTHER MATTERS
Information About Our Executive Officers
INFORMATION ABOUT EXECUTIVE OFFICERS
Name
Age (1)
Positions held over last five years
Time in position
Sempra:
Jeffrey W. Martin
President
March 2020 to present
Chairman
December 2018 to present
Chief Executive Officer
May 2018 to present
Karen L. Sedgwick
Executive Vice President and Chief Financial Officer
January 2024 to present
Chief Administrative Officer
December 2021 to December 2023
Chief Human Resources Officer
September 2020 to December 2023
Senior Vice President
September 2020 to December 2021
Justin C. Bird
Executive Vice President
January 2024 to present
Chief Executive Officer, Sempra Infrastructure
November 2021 to present
Chief Executive Officer, Sempra LNG
April 2020 to November 2021
Caroline A. Winn
Executive Vice President
July 2025 to present
Chief Executive Officer, SDG&E
August 2020 to July 2025
Diana L. Day
Corporate Secretary
May 2025 to present
Chief Legal Counsel
January 2024 to present
Deputy General Counsel
October 2022 to January 2024
Senior Vice President, SDG&E
August 2020 to October 2022
Chief Risk Officer, SDG&E
August 2019 to October 2022
General Counsel, SDG&E
January 2019 to October 2022
Lisa M. Larroque Alexander
Senior Vice President, Human Resources
January 2025 to present
Senior Vice President, Corporate Affairs
April 2020 to present
Dyan Z. Wold
Vice President, Controller and Chief Accounting Officer
July 2025 to present
Chief Accounting Officer, Sempra Infrastructure
September 2023 to July 2025
Vice President and Controller, Sempra Infrastructure
December 2021 to July 2025
Controller, Sempra LNG
November 2019 to December 2021
(1) Ages are as of February 26, 2026.
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INFORMATION ABOUT EXECUTIVE OFFICERS
Name
Age (1)
Positions held over last five years
Time in position
SDG&E:
Scott B. Crider
President
February 2025 to present
Senior Vice President, External and Operations Support
June 2022 to January 2025
Senior Vice President, Customer Services and External Affairs
June 2021 to June 2022
Chief Customer Officer
September 2020 to June 2021
Valerie A. Bille
Chief Financial Officer and Senior Vice President, SDG&E and SoCalGas
January 2026 to present
Chief Financial Officer and Senior Vice President
March 2025 to January 2026
Controller, Chief Accounting Officer and Treasurer
August 2020 to January 2026
Vice President
August 2020 to March 2025
Kevin C. Geraghty
Chief Operating Officer
June 2022 to present
Chief Safety Officer
January 2021 to present
Senior Vice President, Electric Operations
July 2020 to June 2022
Robert J. Borthwick
Senior Vice President and General Counsel, SDG&E and SoCalGas
January 2026 to present
Chief Risk Officer, Sempra
May 2023 to January 2026
Deputy General Counsel, Sempra
March 2019 to May 2023
Maritza Mekitarian
Vice President, Controller and Chief Accounting Officer
January 2026 to present
Assistant Treasurer
March 2024 to present
Assistant Controller
January 2024 to January 2026
Director of Financial Planning
September 2021 to January 2024
Financial and Strategic Planning Manager
April 2021 to September 2021
Financial Planning Manager
September 2017 to April 2021
(1) Ages are as of February 26, 2026.
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INFORMATION ABOUT EXECUTIVE OFFICERS
Name
Age (1)
Positions held over last five years
Time in position
SoCalGas:
Maryam S. Brown
Chief Executive Officer
January 2025 to present
President
March 2019 to present
Valerie A. Bille
Chief Financial Officer and Senior Vice President, SoCalGas and SDG&E
January 2026 to present
Chief Financial Officer and Senior Vice President, SDG&E
March 2025 to January 2026
Controller, Chief Accounting Officer and Treasurer, SDG&E
August 2020 to January 2026
Vice President, SDG&E
August 2020 to March 2025
Rodger R. Schwecke
Chief Operating Officer
March 2025 to present
Senior Vice President and Chief Infrastructure Officer
November 2020 to March 2025
Robert J. Borthwick
Senior Vice President and General Counsel, SoCalGas and SDG&E
January 2026 to present
Chief Risk Officer, Sempra
May 2023 to January 2026
Deputy General Counsel, Sempra
March 2019 to May 2023
Erin M. Smith
Senior Vice President, External Affairs and Chief Talent Officer
June 2025 to present
Senior Vice President, Chief Talent, Culture, and Operations Support
Officer
January 2023 to June 2025
Chief Talent and Culture Officer
December 2020 to January 2023
Sara P. Mijares
Chief Accounting Officer
May 2024 to present
Assistant Treasurer
April 2023 to present
Vice President and Controller
July 2022 to present
Vice President of Accounting and Finance
August 2021 to July 2022
Assistant Controller
June 2020 to July 2022
(1) Ages are as of February 26, 2026 .
Human Capital
Our ability to advance our mission to build America’s leading utility growth business by investing in U.S. utilities, modernizing critical infrastructure and deploying next-generation technology at scale largely depends on the safety, engagement, and responsible actions of our employees.
Safety is foundational at Sempra and its subsidiaries. We strive to foster a strong safety culture and reinforce this culture through various policies, programs and systems designed to mitigate the occurrence and extent of safety incidents, including training programs, benchmarking, review and analysis of safety trends, internal compliance assessments and audits, and sharing lessons learned from safety incidents and near misses across our businesses. Our businesses also engage in safety-related scenario planning and simulation, develop and implement operational contingency plans, and review safety plans and procedures with work crews regularly. We also participate in emergency planning and preparedness in the communities we serve and train critical employees in emergency management and response each year. The SST Committee assists the Sempra board of directors in overseeing the company’s oversight programs and performance related to safety, and our executives’ annual incentive compensation is based in part on safety metrics established by the Compensation and Talent Development Committee of the board.
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In addition, we strive to create a high-performing, inclusive and supportive workplace where employees of all backgrounds and experiences feel valued and respected. We invest in recruiting, developing and retaining high-performing employees who represent the communities we serve, and we provide a range of programs for employees, including internal and external mentoring and leadership training and workshops, employee resource groups, and a benefits package including wellness benefits and a tuition reimbursement program. We also invest in internal communications programs, including in-person and virtual learning and networking opportunities as well as regular executive communications to employees on topics of interest. In addition, we offer a variety of employee community service opportunities, and at our U.S. operations, we support employees’ personal volunteering and charitable giving through the charitable matching program of Sempra Foundation, which was founded and is solely funded by Sempra. Employees participate in annual ethics and compliance training, which includes a review of Sempra’s Code of Business Conduct as well as information about resources such as Sempra’s ethics and compliance helpline. We measure culture and employee engagement through a variety of channels including pulse surveys, suggestion boxes and a biannual engagement survey administered by a third party.
We continue to advance our workforce modernization efforts to enhance operational performance. Key elements include retaining high performing talent, streamlining organizational structures, and aligning our workforce with evolving business needs. We intend to shift our workforce toward higher-value roles through talent reskilling and upskilling, redeployment strategies, and driving adoption of artificial intelligence and modern technologies. As we implement these initiatives, we expect certain roles to be consolidated or modified over time. While these actions may result in changes in overall headcount over time, the primary focus is on building a more agile, skilled, and technology-enabled workforce capable of supporting the company’s long-term strategy and value for customers.
The table below shows the number of employees for each of the Registrants at December 31, 2025, as well as the number of those employees represented by labor unions under various collective bargaining agreements that generally cover wages, benefits, working conditions and other terms and conditions of employment. We did not experience any major work stoppages in 2025, and we maintain constructive relations with our labor unions.
NUMBER OF EMPLOYEES
Number of employees
Number of employees covered under collective bargaining agreements
Number of employees covered under collective bargaining agreements expiring within one year
Sempra (1)
SDG&E
SoCalGas
(1) Excludes employees of equity method investees. Includes 3,048 employees, four of whom are covered under collective bargaining agreements, that are included in the disposal group that is classified as held for sale.
COMPANY WEBSITES
The Registrants’ website addresses are:
▪ Sempra – www.sempra.com
▪ SDG&E – www.sdge.com
▪ SoCalGas – www.socalgas.com
We make available free of charge on the Sempra website, and for SDG&E and SoCalGas, via a hyperlink on their websites, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.
The references to our websites in this report are not active hyperlinks and the information contained on, or that can be accessed through, the websites of Sempra, SDG&E and SoCalGas or any other website referenced herein is not a part of or incorporated by reference in this report or any other document that we file with or furnish to the SEC.
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ITEM 1A. RISK FACTORS
When evaluating our company and its businesses and any investment in our or their securities, you should carefully consider the following risk factors and all other information contained in this report and the other documents we file with the SEC (including those filed subsequent to this report). We also may be materially harmed by risks and uncertainties not currently known to us or that we currently consider immaterial. If any of these risks occur, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, our actual results could differ materially from those expressed or implied in our forward-looking statements, and the trading prices of our securities and those of our businesses could decline. These risk factors are not prioritized in order of importance or materiality, and they should be read together with the other information in this report, including in the Consolidated Financial Statements and in “Part II – Item 7. MD&A.”
RISKS RELATED TO SEMPRA
Operational and Structural Risks
Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments.
We are a holding company and substantially all the assets that produce our earnings are owned by our subsidiaries or equity method investees, which are entities we do not control. SI Partners, which primarily constitutes our Sempra Infrastructure reportable segment, will be accounted for as an equity method investment subject to closing the planned sale of 45% of our equity interest, which we expect to occur in the second or third quarter of 2026. Our ability to pay dividends and meet our debt and other obligations largely depends on distributions from our subsidiaries and equity method investees, which in turn depend on their ability to execute their business strategies and generate cash flows in excess of their own expenditures, dividend payments to third-party owners (if any) and debt and other obligations. In addition, our subsidiaries and entities accounted for as equity method investments are all separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be precluded from doing so by legislation, regulation or contractual restrictions, in times of financial distress or in other circumstances. Any inability to access capital from our subsidiaries and equity method investees could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Sempra’s rights to the assets of its subsidiaries and equity method investees are structurally subordinated to the claims of each entity’s trade and other creditors. When Sempra is a creditor of any such entity, its rights as a creditor are effectively subordinated to any security interest in the entity’s assets and any indebtedness of the entity senior to that held by Sempra. In addition, Sempra may elect to make additional capital contributions to its subsidiaries or equity method investments, which are not required to be repaid and are structurally subordinated to claims by creditors of the applicable subsidiary.
Our investments in businesses we do not control expose us to risks.
We have investments in businesses we do not control or manage or in which we share control, including Oncor and SI Partners (subject to closing our planned sale of a portion of our equity interest in SI Partners). We discuss these investments in Note 5 of the Notes to Consolidated Financial Statements. In some cases, we engage in arrangements with or for these businesses that could expose us to risks in addition to our investment, including guarantees, indemnities and loans. For businesses we do not control, we are subject to the decisions of others, which may be adverse to our interests. When we share control of a business with other owners, any disagreements among the owners about strategy, financial, operational, transactional or other important matters could hinder the business from moving forward with key initiatives or taking other actions and could negatively affect the relationships among the owners and the efficient functioning of the business. In addition, irrespective of whether we control these businesses, we would be responsible for certain liabilities or losses related to these businesses, may be subject to disproportional funding obligations for certain matters or priority distributions in favor of other partners or members, and may be required or elect to make additional capital contributions to these businesses. Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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Our business could be negatively affected by activist shareholders.
We have been and may in the future be subject to activist shareholder attention, including proxy solicitations, shareholder proposals or other attempts to effect changes in or assert influence on our board of directors and management. In connection with these efforts, activist shareholders could seek to acquire our capital stock, despite the provisions of our governing documents that may delay, deter or prevent a change of control or other takeover of our company even if our shareholders might prefer such a change of control. At certain ownership levels, these common stock acquisitions could threaten our ability to use some or all of our NOL or tax credit carryforwards if our corporation experiences an “ownership change” under applicable tax rules. Responding to activist shareholders can be costly and time-consuming and requires time and attention from our board of directors and management, diverting their attention from our business strategies.
Any actual or perceived instability in our future direction, inability to execute our strategies, or changes in our board of directors or management team arising from activist shareholder campaigns could be exploited by our competitors and/or other activist shareholders, result in the loss of business opportunities, and make it more difficult to pursue our strategic initiatives or attract and retain qualified personnel and business partners, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Financial and Capital Stock-Related Risks
Successfully executing our five-year capital expenditures plan is subject to risks.
The execution of our five-year capital expenditures plan may not be completed in accordance with current expectations or produce the desired results. Factors that have historically impacted and could continue to impact the amount, timing and types of capital expenditures we make include the cost and availability of financing; economic and market conditions; regulatory decisions; changes in tax law; business opportunities providing desirable rates of return; forecasts related to safety, reliability and load growth, gas system planning and transportation electrification; safety and environmental requirements and climate-related policies; and cooperation of third parties, including customers, partners, suppliers, lenders and others. We discuss these and other relevant factors with respect to each of our businesses below. We aim to finance our five-year capital expenditures plan in a manner that will maintain our investment-grade credit ratings and capital structure, but we may not be able to do so. Any failure to successfully execute our capital expenditures plan could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Settlement provisions contained in forward sale agreements in connection with our ATM program subject us to certain risks.
In November 2024, Sempra established an ATM program, which we discuss in Note 13 of the Notes to Consolidated Financial Statements. We are permitted to sell shares of our common stock in the ATM program pursuant to forward sale agreements, including 4,996,591 shares under existing forward sale agreements that remain subject to future settlement as of February 26, 2026. These forward sale agreements grant each counterparty (forward purchaser) the right to accelerate its forward sale agreement (or, in certain cases, the portion affected by the relevant event) and require us to physically settle the forward sale agreement upon the occurrence of certain events, some of which are not within our control.
A forward purchaser’s decision to exercise this right and require us to physically settle the relevant shares will be made irrespective of our interests, including our capital and other needs. In such cases, we could be required to issue and deliver shares of our common stock under the terms of the physical settlement, which would result in dilution to our EPS and may adversely affect the market price of our common stock and any series of preferred stock we may issue in the future.
The forward price that we expect to receive upon physical settlement of a forward sale agreement will be subject to adjustment on a daily basis based on a floating interest rate factor. If the specified daily rate is less than the applicable spread on any day, this will result in a daily reduction of the forward price. In addition, the forward price will be subject to decrease on certain dates specified in the relevant forward sale agreement by the amount per share of quarterly dividends we expect to declare on our common stock during the term of such forward sale agreement.
We generally have the right, in lieu of physical settlement of any forward sale agreement, to elect cash or net share settlement in respect of any or all of the shares of our common stock subject to each forward sale agreement. If we elect to cash or net share settle all or any part of any forward sale agreement, we would expect to issue a substantially lower number of shares than if we settled by physical delivery, but would not receive the cash for the shares that would have otherwise been issued if we settled the entire forward sale agreement by physical delivery and, as a result, would not derive the same liquidity or credit metrics benefits.
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If the price of our common stock at which purchases are made by a forward purchaser (or its affiliate) exceeds the applicable forward price, we will pay the forward purchaser an amount in cash equal to such difference (if we elect to cash settle) or we will deliver to the forward purchaser a number of shares of our common stock having a market value equal to such difference (if we elect to net share settle). Any such difference could be significant and could require us to pay a significant amount of cash or deliver a significant number of shares of our common stock to a forward purchaser.
The purchase of shares of our common stock by a forward purchaser (or its affiliate) to unwind the forward purchaser’s hedge position could cause the price of our common stock to increase above the price that would have prevailed in the absence of those purchases (or prevent a decrease in such price), thereby increasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that we would owe the forward purchaser upon settlement of the applicable forward sale agreement or decreasing the amount of cash (in the case of cash settlement) or the number of shares (in the case of net share settlement) that the forward purchaser would owe us upon settlement of the applicable forward sale agreement.
The economic interest, voting rights and market value of our outstanding common stock may be adversely affected by any additional equity securities we may issue.
At February 19, 2026, we had 653,284,140 shares of our common stock outstanding. Our businesses have substantial capital needs, and we may seek to raise capital by issuing additional equity, including in our ATM program, or convertible debt securities in potentially significant amounts depending in part on the prevailing market price of our common stock, which at times experiences substantial volatility. Any future issuance of equity or convertible debt securities may materially dilute the voting rights and economic interests of holders of our outstanding common stock and materially adversely affect the trading price of our common stock.
RISKS RELATED TO ALL SEMPRA BUSINESSES
Operational Risks
Our infrastructure and its supporting systems subject us to risks.
Our facilities and the systems that interconnect and/or manage them are subject to risks of, among other things:
▪ equipment or process failures due to aging infrastructure or otherwise
▪ human error
▪ loss or outage of a key technology platform or system
▪ 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
▪ performance below expected levels
Our businesses undertake capital investment projects to construct, replace, operate, maintain and upgrade facilities and systems, but such projects may not be completed or effective at managing these risks and involve significant costs that may not be recoverable in a timely manner or at all. We often rely on third parties, including contractors, to perform work related to these projects and other activities, which may subject us to liability for safety issues or lower standards of work quality. Because some of our facilities are interconnected with those of third parties, including customer-side-of-meter facilities, natural gas pipelines and power generation facilities, the operation of our facilities could also be materially adversely affected by these or similar risks to such third-party systems, which may be unanticipated or uncontrollable by us.
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Additional risks associated with our facilities and systems, which may be beyond our control, include:
▪ failure to meet customer demand for electricity and/or natural gas, including electric or gas outages
▪ gas surges into homes or other properties
▪ release of hazardous or toxic substances, including gas leaks
▪ public contact with energized equipment
▪ worksite accidents and other incidents impacting the health, safety or security of employees, contractors, the public or our infrastructure
▪ failure to respond effectively to catastrophic events
▪ severe weather, which we discuss further in the following risk factor
The occurrence of any of these events could affect supply and demand for electricity, natural gas or other forms of energy, cause unplannedoutages, damage our assets and/or operations or those of third parties on which our businesses rely, damage property owned by customers or others, and cause personal injury or death, such as recent contractor fatalities on certain Sempra Infrastructure projects under construction. In addition, if we are unable to defend and retain title to the properties we own or obtain or retain rights to construct and operate on the properties we do not own in a timely manner, on reasonable terms or at all, we could lose our rights to occupy and use these properties and related facilities, which could prevent, limit or delay existing or proposed operations or projects, increase our costs, and result in breaches of permits or contracts and related impairments, fines or penalties. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We face risks related to severe weather, natural disasters, physical attacks and other similar events.
Our employees and contractors may be harmed and our facilities and infrastructure may be damaged as a result of physical risks, such as extreme temperatures, storms, droughts and other severe weather; natural disasters, including wildfires, land movement, earthquakes, and solar flares; climate-related conditions, including sea level rise and coastal erosion; accidents, including explosions, excavation damage to pipelines and automobile accidents; or acts of terrorism, war or criminality, including physical attacks and unauthorized drone incursions. Because we are in the business of using, storing, transporting and disposing of highly flammable, explosive and radioactive materials and operating highly energized equipment, the risks such incidents pose to our facilities and infrastructure, as well as to the surrounding communities for which we could be liable, are substantially greater than the potential risks to a typical business. Efforts to mitigate these risks could decrease revenues and earnings and/or increase costs, which for our regulated utilities may not be recoverable in rates on a timely basis or at all, including expenditures on infrastructure maintenance and resiliency, physical and employee safety and security, emergency preparedness, wildfire mitigation and grid modernization.
Such incidents, which have occurred from time to time, could result in operational disruptions, electric or gas outages, property damage, personal injury or death and could cause secondary incidents that also may have these or other negative effects, such as fires; leaks or spills of gases, natural gas odorant or radioactive material; damage to natural resources; or other impacts to affected communities. Any of these occurrences could decrease revenues and earnings and/or increase costs, including restoration expenses, amounts associated with claimsagainst us, and regulatory fines, penalties and disallowances. In some cases, we may be liable for damages even though we are not at fault, such as when the doctrine of inverse condemnation applies, which we discuss below under “Risks Related to Sempra California – Operational Risks.” Insurance coverage for these costs may continue to increase or become prohibitively expensive, be disputed by insurers, or become unavailable for certain of these risks or at adequate levels or in certain geographic locations, and any insurance proceeds may be insufficient to cover our losses or liabilities due to limitations, exclusions, high deductibles, failure to comply with procedural requirements or other factors. We discuss the risks related to insurance for wildfire liabilities below under “Risks Related to Sempra California – Operational Risks.” Such incidents that do not directly affect our facilities may impact our business partners, supply chains and transportation and communication channels, which could negatively affect our ability to operate. Moreover, weather-related incidents have become more prevalent, unpredictable and severe due to climate change or other factors. As a result, these incidents could have a greater impact on our businesses than currently anticipated and, for our regulated utilities, rates may not be adequately or timely adjusted to reflect any such increased impact. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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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.
Cybersecurity and Technology Resiliency
Our significant reliance on complex technologies and increasing deployment of new technologies, such as advanced forms of automation and artificial intelligence and virtualization of many business activities, represent large-scale opportunities for attacks on or failures of our information systems, the energy grid and our other infrastructure. Our digitalization and grid modernization efforts, including the networking of operational technology assets such as substations, continue to increase the potential vulnerabilities and points of failure in our systems. We are also at risk of attacks on, vulnerabilities in or other failures of technologies and systems used by certain third-party vendors, regulators and/or ISOs, including third-party systems that are integral to our electric utilities’ operations in their respective ISO markets. Viruses, ransomware, malware and other forms of cyber-attacks targeting utility systems and other energy infrastructure continue to increase in sophistication, magnitude and frequency, may not be recognized until launched against a target and may further escalate during periods of heightened geopolitical tensions. Adversaries increasingly use artificial intelligence to develop new hacking tools, exploitvulnerabilities, obscure malicious activities and increase the difficulty of detecting threats. Accordingly, we may be unable to anticipate these techniques or to implement adequate preventative measures, making it impossible to eliminate these risks.
Although we make significant investments in risk management, technology resiliency and cybersecurity measures for the protection of our systems and data, these measures could be insufficient or otherwise fail, particularly against unknown software flaws, insider threats, attacks involving sophisticated adversaries, including nation-state actors, or outages involving key technology vendors and systems. The costs and operational consequences of implementing, maintaining and enhancing these measures are significant and expected to increase to address evolving cyber risks. We increasingly rely on third-party vendors to deploy new technologies and host, maintain and update our systems (including providing security updates), and these third parties may not have adequate risk management, technology resiliency and cybersecurity measures with respect to their systems or may fail to timely provide and install software updates. Certain of our key externally hosted systems depend on global cloud service providers as well as their respective vendors, some of which have experienced significant system failures and outages in the past.
Although we have not experienced a material breach of our information systems or data, we and some of our vendors have been and will likely continue to be subject to breaches of and attempts to gainunauthorized access to our systems or data or efforts to otherwise disrupt our operations. Any actual or perceived noncompliance with applicable legal or regulatory requirements or any incidents impacting our or our vendors’ systems, the integrity of our data or assets or the energy grid could result in disruptions to our business operations; legal or regulatory compliance failures; inability to produce accurate and timely financial statements; energy delivery failures; financial and reputational loss; litigation; and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Although we currently maintain cyber liability insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover the costs associated with a cybersecurity incident, and this insurance may not continue to be available on acceptable terms.
Data Security and Governance
Our businesses collect, process and retain large volumes of data, including personal, sensitive and confidential information from customers, employees, contractors and other third parties. SDG&E and SoCalGas are increasingly required to disclose large amounts of data (including customer personal information and energy use data) to support state energy initiatives, increasing the risks of inadvertent disclosure or unauthorized access of sensitive information. Our businesses operating in California are subject to the California Consumer Privacy Act, which requires companies that collect information about California residents to, among other things, disclose their data collection, use and sharing practices; allow consumers to opt out of certain data sharing with third parties; and assume liability for unauthorized disclosure of certain highly sensitive personal information. Certain of our other businesses may operate in jurisdictions with similar laws.
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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.
We will continue to incur costs related to our deployment of artificial intelligence and compliance with applicable laws and regulations governing data collection, processing and retention. Any actual or perceived noncompliance could result in reputational harm, enforcement actions or other proceedings and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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.
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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.
We actively seek opportunities in the market through acquisitions, partnerships, JVs and divestitures, and we may be unable to complete or realize the anticipated benefits from such transactions.
We diligently analyze the financial viability of acquisitions, divestitures, partnerships and JVs we pursue. However, our diligence may prove to be insufficient and there could be latent or unforeseendefects. In addition, we may not realize the anticipated benefits from future transactions for various reasons, including difficulties integrating or separating operations and personnel effectively or in a timely manner, higher or unexpected transaction or operating costs, unknown liabilities, and fluctuations in markets. We discuss these and other risks related to our planned sale of a portion of our equity interest in SI Partners below under “Risks Related to Sempra Infrastructure – Risks Related to Planned Sales of Certain Assets and Businesses.” Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We face risks related to activities and projects intended to advance new energy-related technologies.
We participate in research, development and demonstration projects and other activities designed to develop and implement new technologies in the energy space, including those related to hydrogen, liquefaction, energy storage, microgrids, carbon sequestration, wildfire mitigation and grid modernization. These activities and projects involve significant employee time, as well as substantial capital resources, and we may be required to impair or write off amounts we have invested if any project is unsuccessful or its book value is less than the amount of our investment. As has happened in the past, regulators may deny rate recovery to our regulated utilities for some of these investments. We have sought and continue to seek a variety of related federal and state funding opportunities for these activities and projects, such as government incentives and subsidies under the IRA, some of which were revised by the OBBBA. These efforts can involve significant compliance requirements and have not always been successful in securing funding on acceptable terms or at all. In addition, the timing to complete these activities and projects is inherently uncertain and may require significantly more resources than we initially anticipate. Moreover, many of these technologies are in the early stage of development and may not prove economically and technically feasible or be accepted by regulators, and the applicable activities and projects may not be completed. If any of these circumstances occur, we may not receive an adequate or any return on our investment, and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
The operation of our facilities depends on good labor relations with our employees and our ability to attract and retain qualified personnel.
Our businesses depend on recruiting, developing and retaining qualified personnel. Several of our businesses have collective bargaining agreements with different labor unions, which are negotiated on a company-by-company basis. At December 31, 2025, employees covered under collective bargaining agreements were 38%, 36% and 56%, respectively, of Sempra’s, SDG&E’s and SoCalGas’ workforce (exclusive of equity method investees), of which the collective bargaining agreements covering 26%, 100% and 0%, respectively, of such employees expire within one year (the SDG&E agreements will expire in August 2026). Any prolonged negotiation or failure to reach an agreement on these labor contracts as they are up for renewal could result in work stoppages or other labor disruptions. Additionally, we have faced a shortage of experienced and qualified personnel in certain specialty operational positions and could experience disruptions from recruiting or retention challenges for personnel in those positions. Any labor disruption, negotiated wage or benefit increases or other challenges, whether due to union activities, employee turnover, labor shortages or otherwise, could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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Our businesses depend on the performance of counterparties.
Our businesses depend on the performance of business partners, customers, suppliers, contractors, and other counterparties under contractual and other arrangements to provide, among other things, services, supplies, equipment or commodities. If they fail to perform their obligations in accordance with these arrangements or elect to exercise early termination rights, we may be unable to meet our obligations and may be required to secure alternative arrangements, if available, or honor our underlying commitments at then-current market prices, which may result in losses or delays or other operational disruptions. Any efforts to enforce the terms of these arrangements through legal or other means could involve significant time and costs and may not succeed. We may not be able to secure replacement agreements on favorable terms, in a timely manner or at all if any of these arrangements terminate. We often face counterparty credit risk with respect to customers, suppliers, and other counterparties and, although we perform credit analyses prior to extending credit or entering into transactions with such counterparties, we may not be able to collect the amounts owed to us. Volatility and disruptions in capital and credit markets could have a negative impact on our counterparties and their ability to meet their obligations. SI Partners also faces risks related to doing business with PEMEX and the CFE, which are Mexican state-owned enterprises, including their financial solvency and performance of their respective contractual obligations. Any delay or default in payment could result in our recording of a provision for expected credit losses on past due receivable balances and lower revenues, as was the case in 2024 and 2025 for a customer at SI Partners. The failure of any of our counterparties to perform their obligations could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Financial Risks
Our debt service obligations expose us to risks.
We have significant debt service obligations and an ongoing need for significant amounts of additional capital, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects by, among other things:
▪ making it more difficult and costly to service, pay or refinance debts as they come due, particularly when interest rates increase or economic or industry conditions are otherwise unfavorable
▪ limiting flexibility to pursue strategic opportunities or react to business developments or industry changes causing lenders to require materially adverse terms for new debt, such as restricting uses of proceeds, imposing liens on our assets and limiting our ability to incur additional debt, pay dividends, repurchase stock, or receive distributions from subsidiaries or equity method investees
The availability and cost of financing could be negatively affected by market and economic conditions and other factors.
Our businesses are capital-intensive, with significant and increasing capital spending expected in future periods. In general, we rely on long-term debt to fund a significant portion of our capital expenditures and to repay or refinance outstanding debt, and we rely on short-term debt to fund a significant portion of day-to-day operations. Certain of our businesses also rely on other funding sources, such as Sempra Infrastructure’s use of capital contributions from its owners and various forms of project financing, which may involve guarantees, indemnities or other arrangements that expose us to additional risks, such as potential losses upon the occurrence of events related to the development, construction, operation or financing of the applicable projects. Sempra has also raised and may continue to seek capital by issuing equity, including in our ATM program, or selling equity interests in our subsidiaries or investments.
External sources of capital may not be adequate or available on reasonable terms, in a timely manner or at all. Limitations on the availability of credit, increases in interest rates or credit spreads due to inflation or otherwise or other negative effects on the terms of any financing we pursue could cause us to fund operations and capital expenditures at a higher cost or fail to raise our targeted amount of funds, which could negatively impact our ability to meet contractual and other commitments, progress development projects, make non-safety related capital expenditures and effectively sustain operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
In addition to market and economic conditions, factors that can affect the availability and cost of capital include:
▪ adverse changes to laws and regulations
▪ for Sempra and SDG&E, risks related to California wildfires
▪ for Sempra, SDG&E and SoCalGas, any deterioration of or uncertainty in the political or regulatory environment for companies operating in California
▪ credit ratings downgrades
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Credit rating agencies may downgrade our credit ratings or place them on negative outlook, and our efforts to maintain these ratings could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects in development.
Credit rating agencies routinely evaluate Sempra, SDG&E, SoCalGas, SI Partners and certain of our other businesses, whose ratings are based on many factors, including, as applicable, the ability to generate cash flows; terms and levels of indebtedness, including the credit rating agencies’ treatment of certain types of indebtedness, such as subordinated indebtedness which is given partial equity credit but carries a higher interest rate than comparable senior indebtedness; overall financial strength; specific transactions or events, such as share repurchases and significant litigation; the status of certain capital projects; and general economic and industry conditions. The Rating Agencies also have specified certain events that could lead to negative ratings actions, including, among others:
▪ weakening of certain financial measures or failure to meet certain financial credit metrics
▪ ratings downgrades at certain affiliated entities
▪ for Sempra, expansion of unregulated businesses in a manner inconsistent with its present level of credit quality
▪ for Sempra and SDG&E, catastrophic wildfires caused by SDG&E or any other California electric IOU that participates in the Wildfire Fund and Continuation Account
▪ for SDG&E and SoCalGas, a deterioration of the legislative or regulatory environment, including credit negative outcomes of regulatory proceedings
▪ for Sempra and SI Partners, the PA LNG Phase 1 project or PA LNG Phase 2 project experiencing higher construction costs, delays or other challenges
In an effort to maintain these credit ratings, we may seek to reduce our outstanding indebtedness or our need for additional indebtedness by reducing or postponing discretionary, non-safety or reliability related capital expenditures or investments in new businesses. We may also issue additional equity securities, including in our ATM program, or sell additional equity interests in our subsidiaries or development projects. We may not be able to complete any such equity sales on acceptable terms or at all, and any new equity issued by Sempra may dilute the voting rights and economic interests of Sempra’s existing equity holders. Any such outcome could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.
Although we aim to maintain or improve these credit ratings, they could be downgraded or subject to other negative rating actions at any time, such as S&P’s January 2025 actions that revised Sempra’s outlook to negative from stable and downgraded SoCalGas’ issuer credit rating, and Moody’s March 2025 action that revised Sempra’s outlook to negative from stable. A downgrade of any of our businesses’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, could materially adversely affect the interest rates at which borrowings can be made and debt securities issued and the various fees on our credit facilities. This could make it more costly to borrow money, issue securities and/or raise other types of capital, any of which could reduce our ability to meet our debt obligations and contractual commitments and, in the case of our regulated utilities, increase customer rates, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We discuss these credit ratings in “Part II – Item 7. MD&A - Capital Resources and Liquidity.”
We do not fully hedge our assets or contract positions against changes in commodity prices or interest rates, and for positions that are hedged, our hedging mechanisms may not mitigate our risk or reduce our losses as intended.
We use forward contracts, futures, financial swaps and/or options, among other mechanisms, to hedge a portion of our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity in an effort to reduce our, and for SDG&E and SoCalGas, customers’ financial exposure related to commodity price fluctuations. In addition, we have used and may continue to use similar financial instruments to hedge against changes in interest rates. The extent to which we hedge our positions varies over time. Certain derivative instruments are recorded at fair value through earnings to reflect movements in the price of the derivative, which has recently and could in the future create volatility in our earnings. The effect of such commodity derivative instruments for SDG&E and SoCalGas are passed through to customers in rates without markup. To the extent we have unhedged positions, if any hedging counterparty fails to fulfill its contractual obligations, or if our hedging strategies do not work as intended, fluctuating commodity prices and interest rates could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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Risk management procedures may not prevent or mitigate losses.
Although we have risk management and control systems designed to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended or function as expected. In addition, daily VaR and loss limits, which are primarily based on historic price movements and which we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” may not protect us from losses if prices significantly or persistentlydeviate from historic prices. As a result of these and other factors, our risk management procedures and systems may not prevent or mitigate losses that could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
An impairment of our long-lived assets could result in a material charge to earnings.
We test long-lived assets, including equity method investments, for recoverability when events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the assets. We could experience events or changes in circumstances from, among other things, (i) an inability to operate our existing facilities; (ii) an inability to collect from customers; (iii) changes to laws or regulations or other circumstances affecting the energy sector or our assets in Mexico; (iv) adverse rulings in lawsuits, binding arbitrations, regulatory proceedings, audits and other proceedings materially impacting our businesses and (v) more generally any loss of permits or approvals that requires us to adjust or cease certain operations and any failure to complete or receive an adequate return on our investments in capital projects. A material charge to earnings from an impairmentloss could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Market performance, significant transactions or changes in other assumptions could require unplanned contributions to pension and PBOP plans.
Sempra, SDG&E and SoCalGas provide defined benefit pension and PBOP plans to eligible employees and retirees. The cost of providing these benefits is affected by many factors, including the market value of plan assets, the partial termination of Sempra’s pension plan in connection with the planned sale of a portion of our equity interest in SI Partners and the other factors described in Note 9 of the Notes to Consolidated Financial Statements and “Part II – Item 7. MD&A – Capital Resources and Liquidity.” A decline in the market value of plan assets or an adverse change in any of these other factors could cause a material increase in our funding obligations for these plans, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Legal and Regulatory Risks
We face risks related to the evolving regulatory environment, including failures or delays in obtaining and maintaining franchises and other required approvals and potential negative impacts of our legislative and regulatory advocacy efforts.
The industries in which we operate are subject to extensive regulation, increasing regulatory uncertainty and political influence and polarization.
Our businesses require numerous permits, licenses, rights-of-way, franchises, certificates and other approvals from federal, state, local and foreign governmental agencies. These approvals may not be granted in a timely manner (including due to potential staffing and funding issues at regulatory agencies) or at all or may be modified, rescinded or fail to be extended for a variety of reasons, including due to legal or regulatory changes or political considerations. The City of San Diego is studying the feasibility of municipalization as a potential alternative to SDG&E’s existing electric franchise agreement, and various aspects of SDG&E’s natural gas and electric franchise agreements have also been challenged in a lawsuit that we discuss in Note 16 of the Notes to Consolidated Financial Statements. At SI Partners, amendments to Mexico’s Constitution and the 2025 Energy Laws have increased government control and participation in the energy sector and may create novel challenges for infrastructure development and operations. Obtaining or maintaining required approvals could result in higher costs or the imposition of conditions or restrictions on our operations. Further, noncompliance by us or certain of our customers with the terms of these approvals could result in their modification, suspension or rescission and subject us to reduced revenue, fines and penalties. If any of these approvals are suspended, rescinded or otherwise terminated or modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise impracticable, we may be required to adjust or temporarily or permanently cease certain of our operations, sell the associated assets or remove them from service and/or construct new assets intended to bypass the impacted area, in which case we may lose some of our rate base or revenue-generating assets, our development and construction projects may be negatively affected and we may incur impairment charges or other costs that may not be recoverable. The occurrence of any of these events could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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From time to time, we invest funds in projects prior to receiving all regulatory approvals. Any inability to recover funds invested in these projects could materially increase our costs, result in material impairments, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We may be unable to recover any or all amounts invested in such projects if:
▪ there is a delay in obtaining these approvals
▪ any approval is conditioned on changes or other requirements that increase costs or impose restrictions on our existing or planned operations
▪ we fail to obtain or maintain these approvals or comply with them or other applicable laws or regulations
▪ we are involved in litigation that adversely impacts any approval or rights to the applicable property or assets
▪ management decides not to proceed with a project
▪ 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.
We face risks related to environmental and climate change regulation and the costs of the energy transition.
The impacts from efforts to mitigate climate change and related regulations may increase the costs we incur to procure and transmit energy and provide other services. The changes in costs and preferences for lower carbon and renewable energy sources may impact the demand for, consumption of, and types of energy we transmit and distribute.
Environmental and Climate Change Regulation
We are subject to extensive federal, state, regional, local, tribal and foreign laws and regulations relating to climate change and environmental protection. To comply with these laws and regulations, we must expend significant capital and employee resources on environmental monitoring, surveillance and other measures to track and disclose performance; acquisition and installation of pollution control equipment; implementation of environmental safety practices; other mitigation efforts; and emissions fees, taxes, penalties and other payments. These requirements could increase as a result of various factors we may not control, including changes to laws and regulations, many of which are becoming more burdensome in light of increasing environmental concerns and related changes to legal and regulatory frameworks; increased readiness and enforcement activities; delays in the renewal and issuance of permits; evolving expectations of investors and other stakeholders; and changes to the mix of energy we transmit and distribute, any of which could negatively impact our operations, costs and corporate planning, demand for our services, customer affordability, and the scope and economics of proposed infrastructure projects or other capital expenditures. In particular, legislation and regulation designed to reduce GHG emissions and mitigate climate change are proliferating, as we discuss in “Part I – Item 1. Environmental Matters.” California’s goals are facing cost pressures and may experience delays or other challenges that could cause the state to modify its laws and rules, resulting in significant uncertainty. Any failure to comply with these or other environmental laws and regulations may subject us to fines and penalties, including criminalpenalties in some cases, and/or curtailment of our operations.
In addition, we are generally responsible for hazardous substances and other contamination on, and the conditions of, our projects and properties, regardless of when these conditions arose and whether they are known or unknown. We have been and may in the future be required to pay environmental remediation costs at former facilities and off-site waste disposal sites where any of our businesses is identified as a PRP under federal, state and local environmental laws. For our regulated utilities, some or all of these costs may not be recoverable in rates.
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Additionally, California laws requiring expansive disclosures on GHG emissions and other environmental measures, targets and claims subject us to potential liability for these disclosures as well as significant compliance costs and could have other consequences that may be difficult to predict, including negative sentiment from current and potential investors, regulators, legislators or other groups. These California disclosure requirements, which remain subject to rulemaking by CARB and have been the subject of legal challenges, and other voluntary disclosures we make may use different reporting frameworks, methodologies and boundaries from each other, which may further increase compliance costs and the risk of compliance failures and may create confusion for stakeholders. Moreover, these disclosure requirements could increase the risk that we become subject to climate change lawsuits. Defense costs associated with such litigation could be significant, and any adverse outcome could require substantial capital expenditures or payment of substantial penalties or damages.
Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Other Energy Transition Risks
The energy transition in California and elsewhere, including decarbonization goals and increasingly divergent investor sentiment regarding climate change efforts, has led to contradictory expectations from various investors and other stakeholders and uncertainty in long-term investor support, including some investors reducing participation in or divesting from our sector. Maintaining investor confidence and attracting capital at a competitive cost will depend, in part, on demonstrating our ability to address material business risks related to climate and our efforts to help achieve the goals of our consumers and the markets and jurisdictions where we operate. In an effort to maintain a sustainable and durable business risk profile and continue to focus on value creation, Sempra updated its climate aspirations to reflect the changing policy, regulatory, commercial and technological landscape, including stakeholders’ evolving focus on reliability, resiliency and affordability and the pace and impact of climate and other public policies. Sempra aims to have net-zero scope 1 and 2 GHG emissions by 2050 and has an interim aim of 50% scope 1 and 2 GHG emissions reductions by 2035 (this interim target is relative to a 2019 baseline, applies to Sempra California’s operations and Sempra Infrastructure’s Mexico (non-LNG) operations, and may be subject to further revision if Sempra’s planned sale of a portion of its equity interest in SI Partners is completed). Sempra’s, SDG&E’s and SoCalGas’ abilities to advance their respective net-zero and other climate objectives and meet the demand for lower-carbon and reliable energy in California and elsewhere will depend on many factors, some of which we do not control, including supportive federal and state energy laws, policies, incentives, tax credits and regulatory decisions; cost and affordability considerations; development, commercialization and regulatory acceptance of affordable, alternative and lower-carbon energy sources, including cleaner fuels; successful research and development efforts focused on lower carbon technologies that are economically and technically feasible; cooperation from our partners, financing sources and commercial counterparties; and consumers’ decisions and preferences. In addition, we will need to continue to expend capital and employee resources to develop and deploy new technologies and modernize grid systems, which may not be recoverable in rates or, with respect to our businesses that are not regulated utilities, may not be able to be passed through to customers. Even if such costs are recoverable, these costs, coupled with necessary safety and reliability investments, may negatively impact the affordability of SDG&E’s and SoCalGas’ services and, for our businesses that are not regulated utilities, may cause costs to increase to levels that reduce customer demand and growth. Moreover, forecasting specified targets over longer-term periods is inherently uncertain and could be significantly impacted by the trajectory of the energy transition. As a result, although we are dedicated to making progress on our climate aims and are continuing to develop capabilities designed to reduce GHG emissions from our own operations as well as to support consumers’ and markets’ climate goals and applicable legislative and regulatory mandates, we may not be successful in achieving these objectives. We could sufferdifficulties attracting investors and business partners, reputational harm and other negative effects if we do not meet or if we further modify our GHG emissions reduction aims or there are negative views about our environmental disclosures or practices generally.
We develop our capital expenditure plans based on assumptions and forecasts as well as regulatory and compliance requirements, including those related to safety, reliability and load growth, gas system planning, and transportation electrification, which generally assume that California will continue to pursue consistent environmental and climate-related policies. If the federal government continues to reduce its support for grid and infrastructure modernization or takes further action to prohibit California from pursuing its environmental and climate-related policies, or if California changes its policies, the assumptions and forecasts underlying our capital expenditure plans may prove to be inaccurate, and our investment plans could suffer significant negative effects.
The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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We are subject to complex tax and accounting requirements that expose us to risks.
We are subject to complex tax and accounting requirements. These requirements may undergo changes at the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these requirements and any changes to them or how they are implemented, interpreted or enforced could increase our operating costs and materially adversely affect how we conduct our business. New tax legislation, such as the OBBBA, and new regulations or interpretations or changes in tax policies in the U.S., Mexico or other countries in which we do business could negatively affect our tax expense and/or tax balances and our businesses generally. Any failure to comply with these requirements could subject us to fines and penalties, including criminalpenalties in some cases. The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We may be negatively impacted by the outcome of litigation or other proceedings in which we are involved.
Our businesses are involved in a number of lawsuits, appeals, binding arbitrations, regulatory investigations and other proceedings. We discuss material pending proceedings in Note 16 of the Notes to Consolidated Financial Statements. Our businesses also may become involved in proceedings that we do not consider material, such as the approximately 28,000 proofs of claim that have been filed on behalf of persons who assert the right to file lawsuits in the future based on alleged exposure to asbestos in power plants designed and/or built by certain predecessor entities we acquired in connection with our acquisition of our majority interest in Oncor. We have spent, and continue to spend, substantial capital and employee resources on lawsuits and other proceedings. The uncertainties inherent in lawsuits and other proceedings and the broad range of potential outcomes make it difficult to estimate with any degree of certainty the timing, costs and other potential impacts of these matters, and changes or disruptions to judicial systems, such as the nationwide strike by the Mexican judiciary in 2024 in response to judicial reforms and the limitations on operations of U.S. federal courts in 2025 due to lapses in congressional appropriations, could result in delays, increased costs, or unfavorable outcomes. In addition, juries have demonstrated a willingness to grant large awards, including punitivedamages, in response to personal injury, product liability, property damage, nuisance, and other claims. Accordingly, actual costs incurred have and may continue to differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, from insurance or in customer rates. Any of the foregoing could cause reputational damage and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
RISKS RELATED TO SEMPRA CALIFORNIA
Operational Risks
Wildfires in California pose risks to Sempra, SDG&E and SoCalGas.
More and Increasingly Severe Wildfires
In recent years, California has experienced some of the largest wildfires (measured by acres burned and/or structures destroyed) in its history. Frequent and severedrought conditions, inconsistent and extreme swings in precipitation, changes in vegetation, unseasonably warm temperatures, low humidity, strong winds and other factors have increased the duration of the wildfire season and the intensity, prevalence and difficulty of preventing and containing wildfires in California, including in SDG&E’s and SoCalGas’ service territories. Changing weather patterns, including as a result of climate change, could exacerbate these conditions. Certain California local land use policies and forestry management practices, as well as expanded construction and development of residential and commercial projects in high-risk fire areas, could lead to increased third-party claims and greaterlosses related to fires for which SDG&E or SoCalGas may be liable.
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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Future wildfires in SDG&E’s or SoCalGas’ service territories could compromise SDG&E’s and SoCalGas’ electric and natural gas infrastructure and result in further service disruptions, which could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects. We discuss these risks further in this risk factor below and above under “Risks Related to All Sempra Businesses – Operational Risks.”
The Wildfire Legislation
In July 2019 and September 2025, respectively, the 2019 Wildfire Legislation and the 2025 Wildfire Legislation (collectively, the Wildfire Legislation) were signed into law, which we discuss in Note 1 of the Notes to Consolidated Financial Statements. The 2019 Wildfire Legislation established the Wildfire Fund and the 2025 Wildfire Legislation established the Continuation Account, which offer liquidity to reimburse wildfire-related claims incurred by participating California electric IOUs in excess of $1 billion, subject to the coverage of each fund. The Wildfire Legislation’s legal standards for the recovery of wildfire costs may not be implemented effectively or applied consistently. Moreover, the Wildfire Fund and the Continuation Account, if it becomes operative, could be materially reduced, exhausted, or terminated due to claims by SDG&E or other participating IOUs related to fires caused by utility conduct or operations, or SDG&E could fail to maintain a valid annual safety certification from the OEIS or meet other requirements, any of which could result in SDG&E losing eligibility for the Wildfire Legislation’s liability cap and the other protections afforded by these funds. As a result, a fire resulting from the conduct or operations of any participating California electric IOU could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects, with potentially material additional exposure if SDG&E’s conduct or operations is determined to be a cause of a fire and SDG&E is found to have acted imprudently.
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.
The Wildfire Legislation did not change the doctrine of inverse condemnation, which imposes strict liability for certain types of claims (meaning that liability is irrespective of negligence or intent) on a utility whose equipment is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including business interruptionlosses, interest and attorneys’ fees, even if the utility is not found negligent. In the past, the CPUC has denied recovery of incurred costs associated with wildfire claimsdespite the doctrine of inverse condemnation, which was historically based on the ability of a utility to pass such costs through to rate payers. The doctrine of inverse condemnation also is not exclusive of other theories of liability, such as negligence, under which additional liabilities, such as fire suppression, clean-up and evacuation costs, medical expenses, and personal injury, punitive and other damages, could be imposed. We are unable to predict the impact of the Wildfire Legislation on SDG&E’s ability to recover costs and expenses if SDG&E’s equipment is determined to be a cause of a fire.
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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Cost Recovery Through Insurance or Rates
As a result of California’s doctrine of inverse condemnation, substantial losses recorded by insurance companies, and increased wildfire risk, obtaining insurance coverage for wildfires potentially associated with SDG&E’s equipment (or, to a lesser extent, SoCalGas’ equipment) has become increasingly difficult and costly. If these conditions continue or worsen, including as a result of the LA Fires, insurance for wildfire liabilities may become unavailable or may become prohibitively expensive and we may be denied recovery of insurance cost increases through the regulatory process. In addition, insurance for wildfire liabilities may not be sufficient to cover all losses we may incur, or it may not be available to meet the $1.0 billion of primary insurance required by the Wildfire Legislation. Wildfire insurance may also become prohibitively expensive or unavailable for homeowners and businesses in SDG&E’s service territory, potentially increasing SDG&E’s financial exposure if a wildfire is found to be caused by SDG&E’s equipment. We may be unable to recover in rates or from the Wildfire Fund or the Continuation Account the amount of any uninsuredlosses (including amounts paid for self-insurance and other costs). A loss that is not fully insured, is not sufficiently covered by the Wildfire Fund or the Continuation Account and/or cannot be recovered in customer rates could materially adversely affect Sempra’s and one or both of SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
Regulatory Actions Related to Wildfire Mitigation Efforts
Although we expend significant resources on measures designed to mitigate wildfire risks, these measures may not be effective in preventing wildfires or reducing our wildfire-related losses, and their costs may not be fully recoverable in rates. SDG&E is required by California law to submit WMPs for approval by the OEIS and could be subject to increased risks if these plans are not approved in a timely manner or SDG&E is determined to not have substantially complied with its approved plans, including the risk of fines or penalties for non-implementation or denial of its safety certification. Moreover, wildfire mitigation investments incremental to those authorized in a GRC may be subject to reasonableness reviews after they are made and could be subject to disallowances as a result of such reviews, as was the case with the FD issued in connection with SDG&E’s Track 2 request in its 2024 GRC. One of SDG&E’s wildfire mitigation strategies is to de-energize certain circuits for safety when there is elevated weather-related wildfire ignition risk. These “public safety power shutoffs” have been subject to scrutiny by various stakeholders, including customers, regulators and lawmakers, which could increase the risk of regulatory fines and penalties, claims for damages and reputational harm if SDG&E is found not to have acted within applicable guidelines and regulations. Such costs may not be recoverable in rates. Unrecoverable costs, adverse legislation or rulemaking, stakeholder scrutiny, ineffective wildfire mitigation measures or other negative effects associated with these efforts could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
The electricity industry is undergoing significant change .
Electric utilities in California are experiencing increasing deployment of solar and wind generation, including DER, energy storage and energy efficiency and demand management technologies, and California’s environmental policy objectives are accelerating the pace and scope of these changes. This growth will require further modernization of the electric grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, attaining California’s clean energy goals will require sustained investments in transmission and distribution grid modernization, renewable energy integration projects, operational and data management systems, and electric vehicle and energy storage infrastructure, which may increase exposure to overall grid instability and technology obsolescence. The growth of third-party energy storage alternatives and other technologies also may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities. The CPUC is conducting various proceedings regarding DER, including the evaluation of special programs and pilot projects; changes to the planning and operation of the electric grid to prepare for higher penetration of DER; future grid modernization investments; the deferral of traditional grid investments by DER; and the role of the electric grid operator. These proceedings and the broader changes in California’s electricity industry could result in new regulations, policies and/or operational changes that could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
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Most of SDG&E’s customers receive electric commodity service from a load-serving entity other than SDG&E through programs such as CCA and DA. CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, as is the case with the City of San Diego and certain other jurisdictions in SDG&E’s service territory, and DA is currently limited by a cap based on gigawatt hours. Due to this departed load, SDG&E’s historical energy procurement commitments for future deliveries exceed the needs of its remaining bundled customers. To help achieve the goal of ratepayer indifference (as to whether customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The framework is intended to more equitably allocate SDG&E’s historical energy procurement cost obligations among customers served by SDG&E and customers now served by CCA and DA. If the framework or other mechanisms designed to achieve ratepayer indifference do not perform as intended, if the law changes, or if the law is not interpreted or enforced as expected, SDG&E’s remaining bundled customers could experience large increases in rates for ongoing historical commodity costs under commitments made on behalf of CCA and DA customers prior to their departure or, if all such costs are not recoverable in rates, SDG&E could experience material increases in its unrecoverable commodity costs. 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.
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.
Natural gas continues to be the subject of political and public debate, including a desire by some to reduce or eliminate reliance on natural gas as an energy source .
Certain California legislators, regulators and other stakeholders have expressed a desire to limit or eliminate reliance on natural gas as an energy source through increased use of renewable electricity and electrification. Reducing methane emissions also has become a major focus of certain local and state agencies, resulting in passed or proposed legislation, regulation, policies and ordinances to prohibit or restrict the use of natural gas in new buildings, appliances and other applications, including proposed and recently enacted requirements regarding space and water heaters in newly constructed buildings and an open CPUC proceeding to establish long-term gas system infrastructure planning for natural gas utilities in alignment with California’s decarbonization goals. Additionally, customer preferences may drive increased disconnections from gas service. These actions could result in reduced natural gas use over time and changes to rate and cost recovery policies, and the combination of reduced load and increasing costs to maintain the gas system could negatively impact affordability for remaining natural gas customers. Moreover, a substantial reduction in or the elimination of natural gas use in California could result in impairment of some or all of SDG&E’s and SoCalGas’ natural gas infrastructure assets without adequate recovery of investments, if they were not permitted to be repurposed, or if they were required to be depreciated on an accelerated basis or were to become stranded, in which case, SDG&E and SoCalGas could be required to incur significant decommissioning or other costs, which may require additional funding and may not be recoverable in rates. For instance, in a prior proceeding that is now closed, the CPUC evaluated the feasibility of minimizing or eliminating SoCalGas’ Aliso Canyon natural gas storage facility. The authorized storage level and reliance on the facility in general remain subject to a biennial administrative staff review by the CPUC and additional CPUC proceedings. A permanent closure, which could only be achieved through a new CPUC proceeding, could result in an impairment of the facility that could be material, and a closure or significant reduction in authorized capacity could risk energy and electric reliability in the region. Any such outcome could have a material adverse effect on Sempra’s, SoCalGas’ and SDG&E’s results of operations, financial conditions, cash flows and/or prospects.
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SDG&E may incur significant costs and liabilities from its partial ownership of a nuclear facility being decommissioned .
SDG&E has a 20% ownership interest in SONGS, which we discuss in Note 15 of the Notes to Consolidated Financial Statements. SDG&E is responsible for financing its proportionate share of the facility’s expenses and capital expenditures, including those related to decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to risks, including:
▪ the potential release of radioactive material
▪ the potential harmful effects from the former operation of the facility
▪ limitations on the insurance commercially available to cover losses associated with operating and decommissioning the facility
▪ uncertainties with respect to the technological, financial, and political aspects of decommissioning the facility and the long-term storage of radioactive materials
SDG&E maintains the SONGS NDT to provide funds for nuclear decommissioning. Trust assets generally have been invested in equity and debt securities, which are subject to market fluctuations. A decline in the market value of trust assets, an adverse change in the law regarding funding requirements for decommissioning trusts, or changes in assumptions or forecasts related to decommissioning timing and costs could increase the funding requirements for these trusts, which costs may not be fully recoverable in rates. In addition, CPUC approval is required to make withdrawals from the NDT, which may be denied if the expenditures are found to be unreasonable. In addition, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the NDT. Rate recovery for overruns would require CPUC approval, which may be denied.
The occurrence of any of these events could result in a reduction in our expected recovery and have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
Legal and Regulatory Risks
SDG&E and SoCalGas are subject to extensive regulation.
Rates and Other Financial Matters
The CPUC regulates SDG&E’s and SoCalGas’ customer rates and conditions of service, except for SDG&E’s interstate electric transmission and wholesale electric rates and conditions of service, which are regulated by the FERC. The CPUC also regulates SDG&E’s and SoCalGas’ sales of securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters in various ratemaking proceedings. The CPUC periodically approves SDG&E’s and SoCalGas’ customer rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments while incorporating a risk-based decision-making framework, as well as certain settlements with third parties and mandatory social programs. The timing and outcome of ratemaking proceedings can be affected by various factors, many of which are not in our control, including the level of opposition by intervening parties; any rejection by the CPUC of settlements with third parties; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of regulators, customers and other stakeholders. These ratemaking proceedings include decisions about major programs in which SDG&E and SoCalGas make investments under an approved CPUC framework, such as wildfire mitigation, pipeline and storage integrity and safety enhancement programs, but which investments may remain subject to CPUC filings or reasonableness reviews that may result in the disallowance of incurred costs, as was the case with SDG&E’s Track 2 request in its 2024 GRC. SDG&E and SoCalGas also may be required to make investments and incur other costs before they can request rate recovery for certain projects or to comply with proposed legislative and regulatory requirements, including those related to California’s climate goals and policies, before finalization of the requirements and corresponding ratemaking mechanisms, which investments may not ultimately be fully recoverable. Recovery may be delayed and/or insufficient if ratemaking mechanisms involve a significant time lag between when costs are incurred and when those costs are recovered in rates or if there are material differences between the authorized costs embedded in rates (which are set on a prospective basis) and the actual costs incurred. As was the case with respect to the 2024 GRC FD, delays may also result from the regulatory process and the CPUC may deny recovery altogether on the basis that costs were not reasonably or prudently incurred or for other reasons, such as customer affordability. Even if recoverable, simultaneously investing in support of necessary safety and reliability and regulatory requirements and demand for reliable lower-carbon energy may negatively impact the affordability of SDG&E’s and SoCalGas’ services and their and Sempra’s results of operations, financial condition, cash flows and/or prospects.
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A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and return on rate base. The CPUC applies the CCM, which we describe in “Part I – Item 1. Business – Ratemaking Mechanisms” and Note 4 of the Notes to Consolidated Financial Statements, in the interim years to consider changes in the cost of capital using changes in interest rates. Any rate changes due to a downward trigger of the CCM, the denial by the CPUC of an automatic upward trigger of the CCM or further structural changes to the CCM could have a material adverse effect on Sempra’s and the applicable utility’s results of operations, financial condition, cash flows and/or prospects. We discuss the CCM in “Part I – Item 1. Business – Ratemaking Mechanisms – Sempra California – Cost of Capital Proceedings,” and in Note 4 of the Notes to Consolidated Financial Statements.
The FERC regulates electric transmission rates, transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return and rates of depreciation on electric transmission investments, and other similar matters involving SDG&E. These ratemaking mechanisms are subject to many risks similar to those described above regarding CPUC ratemaking proceedings. In particular, SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision had been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019. In October 2024, SDG&E submitted its TO6 filing to the FERC and requested it to be effective January 1, 2025. SDG&E’s TO6 filing proposed, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing, subject to refund; suspended the effective date to June 1, 2025; established hearing and settlement judge procedures; and disallowed the inclusion of the California ISO adder, the last of which SDG&E has appealed. In February 2026, the settlement judge in the TO6 proceeding reported to the FERC that the participants had reached an agreement in principle on all issues in the proceeding. The parties will draft an offer of settlement to be filed with the FERC for approval. Any unfavorable outcome in these proceedings, such as an authorized ROE that is materially lower than the requested ROE, could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
Operational Matters
Our operations are subject to CPUC rules (and similar FERC rules), commonly referred to as “affiliate rules,” relating to transactions among SDG&E, SoCalGas and other Sempra businesses. These rules primarily impact market transactions and marketing activities involving transmission supply and capacity, including sales or other trades of natural gas or electricity within or among SDG&E and SoCalGas and Sempra and its covered affiliates. Noncompliance with these rules, as well as any changes or additions to these rules or their interpretations, could materially adversely affect our operations and, in turn, our results of operations, financial condition, cash flows and/or prospects.
Additionally, the CPUC has regulatory authority related to safety standards and practices, reliability and planning, competitive conditions and a wide range of other operational matters, including restrictions on funding of lobbying or other political activities, promotional advertising and certain other costs, as well as citation and enforcement programs concerning matters such as safety activity, disconnection and billing practices, commodity pricing, resource adequacy and environmental compliance. Many of these standards and citation and enforcement programs are becoming more stringent and could subject a utility to significant penalties and fines, as well as higher operating costs. The CPUC conducts reviews and audits of the matters under its authority and may launch investigations or open proceedings at its discretion, the results of which could include citations, disallowances, fines and penalties, as well as requirements for corrective or mitigation actions to address any noncompliance, any of which may not be sufficiently funded by customer rates or at all. Any such occurrence could result in other regulatory exposure, significant litigation, and reputational harm and could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
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.
We discuss various CPUC and FERC proceedings relating to SDG&E and SoCalGas in Note 4 of the Notes to Consolidated Financial Statements.
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Regulatory and Legislative Changes and Influence of Other Organizations
SDG&E and SoCalGas incur significant capital, operating and other costs associated with regulatory compliance. Sempra, SDG&E and SoCalGas may be materially adversely affected by revisions or reinterpretations of existing or new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies, any of which could change how SDG&E and SoCalGas operate, affect their ability to recover various costs through rates or adjustment mechanisms, require them to incur additional compliance or other costs, including fines and penalties, or otherwise materially adversely affect their and Sempra’s results of operations, financial condition, cash flows and/or prospects.
SDG&E and SoCalGas are also affected by numerous advocacy groups, including California Public Advocates Office, The Utility Reform Network, Utility Consumers’ Action Network and the Sierra Club. Success by any of these groups in directly or indirectly influencing legislators and regulators could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
Failure by the CPUC to adequately reform SDG&E’s electric rate structure could negatively impact Sempra and SDG&E.
The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable energy generation (primarily solar) for residential and business customers. Depending on when the on-site generation is installed, NEM customers receive a full retail rate or a reduced retail rate for energy they generate but do not use that is fed to the utility’s power grid, which results in these customers not paying their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain exceptions, but still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. As more and higher electric-use customers switch to NEM and self-generate energy, the burden on remaining non-NEM customers, who effectively subsidize the unpaid NEM costs, increases, which in turn encourages more self-generation and further increases rate pressure on remaining non-NEM customers.
In December 2023, a new Net Billing Tariff was implemented for customers who interconnect their qualifying on-site renewable energy generation after April 2023. The new Net Billing Tariff revised the NEM structure for new customers with a retail export compensation rate that is better aligned with the value provided to the grid by behind-the-meter energy generation systems and retail import rates that encourage electrification and adoption of solar systems paired with storage. The new Net Billing Tariff is designed to compensate customers for the value of their exports to the grid based on avoided cost. In addition, prior to the fourth quarter of 2025, the electric residential rate structure in California was primarily based on consumption volume, which placed a higher rate burden on customers with higher electric use while subsidizing lower-use customers. In response to California legislation adopted in 2022, the CPUC broadly restructured the way certain residential fixed costs are collected, moving away from volumetric -only charges and incorporating an income-based fixed charge for default residential rates. The intent of such a fixed charge is to allow the utility to collect a greater portion of its fixed costs on a non-volumetric basis, advance the state’s climate goals through end-use electrification and provide a more affordable rate design on average for lower-income customers. The residential fixed charge was implemented in the fourth quarter of 2025. Depending on the effectiveness of the new Net Billing Tariff and fixed charge, which are uncertain, the risks associated with the existing NEM tariff and rate design could continue or increase, including adverse impacts on electricity rates and the reliability of the transmission and distribution system and the potential for increases in customer dissatisfaction, likelihood of noncompliance with CPUC or other safety or operational standards, and power procurement, operating, capital and other costs that may not be recoverable, any of 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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RISKS RELATED TO SEMPRA TEXAS UTILITIES
Operational and Structural Risks
Ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, policies and operations of Oncor.
Various “ring-fencing” measures, governance mechanisms and commitments are in place that create legal and financial separation between Oncor Holdings, Oncor and their subsidiaries, on the one hand, and Sempra and its affiliates and subsidiaries, on the other hand. These measures are designed to enhance Oncor’s separateness from its owners and mitigate the risk that Oncor would be negatively impacted by a bankruptcy or other adverse financial development affecting its owners. These measures subject us and Oncor to various restrictions, including:
▪ seven members of Oncor’s 13-person board of directors must be independent directors in all material respects under the rules of the NYSE in relation to Sempra and its affiliates and any other owners of Oncor, and also must have no material relationship with Sempra or its affiliates or any other owners of Oncor currently or within the previous 10 years; of the six remaining directors, two must be designated by Sempra, two must be designated by Oncor’s minority owner, TTI, and two must be current or former Oncor officers
▪ Oncor will not pay dividends or other distributions (except for contractual tax payments) if (i) a majority of Oncor’s independent directors or any of the directors appointed by TTI determines that it is in the best interest of Oncor to retain such amounts to meet expected future requirements, (ii) the payment would cause Oncor’s debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT, or (iii) unless otherwise allowed by the PUCT, Oncor’s senior secured debt credit rating by any of the Rating Agencies falls below BBB (or Baa2 for Moody’s)
▪ certain “separateness measures” must be maintained to reinforce the legal and financial separation of Oncor from Sempra, including a requirement that dealings between Oncor and Sempra or Sempra’s affiliates (other than Oncor Holdings and its subsidiaries) must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or membership interests for any entity other than Oncor
▪ a majority of Oncor’s independent directors and the directors designated by TTI that are present and voting (with at least one required to be present and voting) must approve any annual or multi-year budget if the aggregate amount of capital expenditures or O&M in the budget differs by more than 10% from the corresponding amounts in the budget for the preceding fiscal year or multi-year period, as applicable
As a result of these measures, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning, risk management, climate-related activities, cybersecurity practices and other important matters. Moreover, all directors of Oncor, including the directors we have appointed, have considerable autonomy and have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may in some cases be contrary to our interests. To the extent the directors approve or Oncor otherwise pursues actions that are not in our interest, our results of operations, financial condition, cash flows and/or prospects may be materially adversely affected.
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Industry-Related Risks
Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or ERCOT market could negatively affect Oncor.
Oncor operates in the electric utility industry and is subject to many of the same or similar risks as SDG&E and SoCalGas as we describe above under “Risks Related to All Sempra Businesses” and “Risks Related to Sempra California,” particularly with respect to our operational risks, financial risks and specifically regulation by federal, state, and local legislative and regulatory authorities regarding rates and other financial and operational matters. Oncor is subject to a complex regulatory oversight structure with several different regulators, including the PUCT, FERC, North American Electric Reliability Corporation and Texas Reliability Entity, Inc. Oncor operates in the ERCOT market, which is subject to oversight by the PUCT and the Texas legislature, either of which could impose changes to the ERCOT market that could impact Oncor. In ERCOT, rates are set by the PUCT based on a historical test year, and as a result, the rates Oncor is allowed to charge generally will not exactly match its costs at any given point in time and it may not be able to timely or fully recover its actual costs and/or earn its full return on invested capital, particularly during periods of increased capital spending by Oncor, high inflation, or increases in interest rates, storm-related costs, and other operating costs relative to Oncor’s most recent base rate review. Further, the levels and timing of any approved recovery could significantly differ from Oncor’s requests. In addition to requests to recover its costs, Oncor’s rate proceedings may contain other requests. Failure to receive approval of its requests in any rate proceeding could adversely impact Oncor, and those impacts could be material.
The costs and burdens of complying with the various federal, state, and local legislative and regulatory requirements applicable to Oncor and adjusting Oncor’s business and operations in response to legislative and regulatory developments, including changes in ERCOT, and any fines or penalties that could result from any noncompliance, may have a material adverse effect on Oncor. In addition, insufficient electric generation capacity within ERCOT or significant changes within ERCOT or to the ERCOT market structure that impact transmission and distribution utilities, including adverse publicity or public perception or additional regulatory requirements or oversight, could materially adversely affect Oncor. Moreover, legislative, regulatory, market or industry activities could adversely impact Oncor’s collections and cash flows and jeopardize the predictability of utility earnings. For instance, in June 2025, legislation was signed into law to reduce regulatory lag on transmission and distribution capital investments through the UTM process, which we describe in “Part I – Item 1. Business – Ratemaking Mechanisms.” Oncor anticipates filing a UTM on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result has recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. However, the PUCT has not finalized rules with respect to use of the UTM, and as a result any positions Oncor has taken with respect to interpreting the legislation could be revised as a result of the PUCT’s final rules and interpretations, and such revisions could have a material adverse impact on our results of operations, financial condition, cash flows and/or prospects.
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.
If Oncor does not successfully manage these risks and respond to any other applicable legislative, regulatory, market or industry developments, Oncor could suffer a deterioration in its results of operations, financial condition, cash flows and/or prospects, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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Financial Risks
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 desiredimprovements 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.
Because our commitments to the PUCT prohibit us from making loans to Oncor, we may elect to increase our capital contributions to Oncor if it is unable to meet its capital requirements, access sufficient capital, or raise capital on favorable terms. Any such investments could be substantial, would reduce the cash available to us for other purposes, may not be recovered, and could increase our indebtedness, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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Sempra could incur substantial tax liabilities if EFH’s 2016 spin-off of Vistra is deemed to be taxable.
As part of its bankruptcy proceedings, in 2016, EFH distributed all the outstanding shares of common stock of its subsidiary Vistra Corp. (formerly Vistra Energy Corp. and referred to herein as Vistra) to certain creditors of TCEH LLC (the spin-off), and Vistra became an independent, publicly traded company. Vistra’s spin-off from EFH was intended to qualify for partially tax-free treatment to EFH and its shareholders under Sections 368(a)(1)(G), 355 and 356 of the U.S. Internal Revenue Code of 1986 (as amended) (collectively referred to as the Intended Tax Treatment). In connection with and as a condition to the spin-off, EFH received a private letter ruling from the IRS regarding certain issues relating to the Intended Tax Treatment, as well as tax opinions from counsel to EFH and Vistra regarding certain aspects of the spin-off not covered by the private letter ruling.
In connection with the merger of EFH with a subsidiary of Sempra in 2018 (the Merger), EFH received a supplemental private letter ruling from the IRS and Sempra and EFH received tax opinions from their respective counsels that generally provide that the Merger will not affect the conclusions reached in, respectively, the IRS private letter ruling and tax opinions issued with respect to the spin-off described above. Similar to the IRS private letter ruling and opinions issued with respect to the spin-off, the supplemental private letter ruling is generally binding on the IRS and any opinions issued with respect to the Merger are based on factual representations and assumptions, as well as certain undertakings, made by Sempra and EFH. If such representations and assumptions are untrue or incomplete, any such undertakings are not complied with, or the facts upon which the IRS supplemental private letter ruling or tax opinions (which will not impact the IRS position on the transactions) are based are different from the actual facts relating to the Merger, the tax opinions and/or supplemental private letter ruling may not be valid and could be challenged by the IRS. Even though Sempra Texas Holdings Corp. would have administrative appeal rights if the IRS were to invalidate its private letter ruling and/or supplemental private letter ruling, including the right to challenge any adverse IRS position in court, any such appeal would be costly, subject to uncertainties and could fail. If it is ultimately determined that the Merger caused the spin-off not to qualify for the Intended Tax Treatment, Sempra, through its ownership of Sempra Texas Holdings Corp., could incur substantial tax liabilities, which would materially reduce the value associated with our investment in Oncor and could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
RISKS RELATED TO SEMPRA INFRASTRUCTURE
Operational Risks
Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels or generate expected earnings or cash flows.
Energy Infrastructure Projects
We are involved in a number of energy infrastructure projects in various stages of development and construction, which subject us to numerous risks. Success in developing each project depends on, among other things:
▪ our financial condition and cash flows and other factors that impact our ability to invest sufficient funds in the project, including for preliminary activities conducted before we determine whether the project is viable
▪ project assessment and design and our ability to foresee and incorporate emerging trends and technologies
▪ our ability to reach a positive FID or meet other milestones, which may be influenced by factors outside our control, including the global economy and energy and financial markets, actions by regulators, internal and external approval requirements, and many of the other factors described in this risk factor
▪ negotiation of satisfactory EPC agreements and renegotiation in the event of delays in reaching an FID or other specified deadlines
▪ identification of suitable partners, customers, contractors, suppliers and other necessary counterparties
▪ progressing relationships from MOUs, HOAs or other non-binding arrangements to execution of binding, definitive agreements
▪ negotiation and maintenance of satisfactory equity, purchase, sale, supply, transportation and other appropriate commercial agreements, and satisfaction of any conditions to effectiveness of such agreements, including reaching an FID within agreed timelines
▪ timely receipt and maintenance of required governmental permits, licenses and other authorizations on acceptable terms
▪ our project partners’, contractors’, equipment providers’, lenders’ and other vendors’ and counterparties’ willingness and financial or other ability to fulfill their contractual commitments
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▪ timely, satisfactory and on-budget completion of construction, which could be negatively affected by engineering problems; stakeholder relations issues, such as the opposition by some members of the Yaqui tribe to the construction of the Guaymas-El Oro segment of the Sonora pipeline, which we discuss in in Note 1 of the Notes to Consolidated Financial Statements; work stoppages; unavailability or increased costs of materials, equipment, labor and commodities due to inflation, tariffs or supply chain or other issues; and a variety of other factors, many of which we discuss above under “Risks Related to All Sempra Businesses – Operational Risks” and elsewhere in this risk factor
▪ 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
▪ obtaining satisfactory financing for the project
▪ the absence of hidden defects or inherited environmental liabilities on the project site
▪ timely and cost-effective resolution of any litigation or unsettled property rights affecting the project
▪ geopolitical events and other uncertainties
Any failures with respect to the above factors or other factors relevant to any particular project could involve additional costs, otherwise negatively affect our ability to successfully complete the project and force us to impair or write off amounts we have invested in the project. If we are unable to complete a development project, if we experience delays, or if construction, financing or other project costs exceed our estimated budgets and we are required to make additional capital contributions, we may not receive an adequate or any return on our investment and other resources expended on the project and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
The operation of existing facilities and any future projects we complete involves many risks, including the potential for unforeseen design flaws, engineering challenges, or breakdowns of facilities, equipment or processes; labor disputes or shortages; fuel interruption; environmental contamination; increasing regulatory requirements, including from regulations aiming to reduce GHG emissions; and the other operational risks that we discuss above under “Risks Related to All Sempra Businesses – Operational Risks.” Any of these events could lead to our facilities being idle or operating below expected levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
LNG Projects
In addition to the risks described above that are applicable to all our energy infrastructure projects, our LNG projects, which we discuss in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure,” also face distinct disadvantages relative to some LNG projects being pursued by other project developers, including:
▪ The proposed Cameron LNG Phase 2 project is subject to certain restrictions and conditions under the JV project financing agreements for the Cameron LNG Phase 1 facility and requires unanimous consent of all the members, including with respect to the equity investment obligation of each member. We may not be able to satisfy these conditions, receive members’ consent, obtain satisfactory conclusion on the EPC process, or obtain the extension of our non-FTA approval, in which case our ability to develop the Cameron LNG Phase 2 project would be jeopardized.
▪ The ECA LNG projects under construction and in development are subject to the Mexican regulatory process and an overlay of U.S. regulation for natural gas exports to LNG facilities in Mexico, which are not well developed and, among other factors, contributed to delays in obtaining a necessary permit from the Mexican government for the ECA LNG Phase 1 project and could cause similar delays or other hurdles in the future. In September 2025, we submitted a filing with the DOE to extend the construction deadline associated with our non-FTA permits for the ECA LNG Phase 1 project until the end of summer 2026, but we may not receive this extension on a timely basis or at all. In addition, the Baja California region does not have extensive sources of natural gas, and at times, natural gas supply to the region is severely constrained and may impact our costs and our ability to source all feed gas required under our ECA LNG Phase 1 supply contracts. Further, while we do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility, we expect construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has a firm storage and nitrogen injection service agreement with Shell that expires in May 2028.
▪ The PA LNG Phase 1 project under construction is located at a greenfield site and is therefore subject to certain disadvantages relative to projects being constructed or developed at brownfield sites, such as increased time and costs to develop and construct the project due to lack of existing infrastructure. The PA LNG Phase 2 project under construction is located at the site of the PA LNG Phase 1 project and is therefore subject to potential disadvantages, such as increased complexity of integrating new facilities with existing infrastructure.
Development and operation of these or any other LNG projects will depend on the expansion of our existing pipeline interconnections or the ability to permit and construct new pipeline facilities, each of which may require us to enter into additional pipeline interconnection agreements with third-party pipelines, which may not be possible on reasonable terms or at all.
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The capital requirements for our LNG projects can be significant, even if we do not reach a positive FID. As has happened in the past, our proposed facilities may not be completed in accordance with estimated timelines or budgets or at all as a result of the above or other factors, and delays, cost overruns or our inability to complete one or more of these projects could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We face risks from increasing competition.
The markets in which we operate are characterized by numerous capable competitors, many of which have extensive and diversified development and/or operating experience domestically and internationally and financial resources similar to or greater than ours. In particular, the natural gas pipeline, storage and LNG market segments have been characterized by strong and increasing competition for winning new development projects and acquiring existing assets. These competitive factors could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We are exposed to additional competitive risks in connection with our LNG projects. Our ability to reach a positive FID for each development project and, if a project is completed, the overall success of the project depend in part on global energy markets, which can increase competition for global LNG demand in a number of ways. In general, depressed natural gas and LNG prices in the markets intended to be served by any of our projects, including as a result of global oil prices and their associated current and forward projections or other factors, could reduce the pricing and cost advantages of exporting natural gas and LNG produced in North America, which could lead to decreased demand from our projects. Although demand for natural gas is currently strong due to increased focus on energy security and climate aims, a reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, reduced economic activity in general, or as a result of calls by some to limit or eliminate global reliance on natural gas. Further, because LNG projects take a number of years to develop and construct, it is difficult to match current and expected demand with the projected supply from projects under development. Moreover, shifts in U.S. and foreign energy policy could impact supply, demand and other matters critical to LNG projects, such as permitting and other approval processes. These factors could delay or hamper the development of U.S. LNG export facilities and make LNG projects in other parts of the world more feasible and competitive with LNG projects in North America, thus increasing supply and competition for global LNG demand. Any of these occurrences could impact competition and prospects for developing LNG projects and negatively affect the performance and prospects of any of our projects that are or become operational, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We may not be able to secure, maintain, extend or replace long-term supply, sales or capacity agreements.
Certain of SI Partners’ projects, including the ECA Regas Facility, Cameron LNG JV and all of its LNG projects under construction, have long-term agreements with a limited number of customers. The long-term nature of these agreements and the small number of customers exposes us to risks, including increased credit risks and amplified impacts of disputes or other similar issues, which we have experienced in the past. Any such issues that arise in the future with respect to these long-term contracts could lead to significant legal and other costs, result in termination of certain key contracts and negatively impact the reliability of revenues from the applicable projects and the prospects of any implicated development projects. Any such event could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
SI Partners’ obligations and those of its counterparties, such as its LNG customers, are contractually subject to suspension or termination for force majeure events, which generally are beyond the control of the parties. Force majeure declarations may have attendant negative consequences, such as loss or deferral of revenue arising from non-deliveries of natural gas from suppliers or LNG to customers in certain circumstances. Also, certain force majeure events may impact the contractors constructing SI Partners’ projects, which may result in delays or increased costs. SI Partners may have limited available remedies, including limitations on damages that may prohibit recovery of all costs incurred. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
SI Partners’ ability to secure new or maintain or extend existing long-term sales or capacity agreements for its natural gas pipeline operations depends on, among other factors, demand for and supply of LNG and/or natural gas from its transportation customers, which may include our LNG facilities. A decrease in demand for or supply of LNG or natural gas from such customers or the occurrence of other events that hinder SI Partners from maintaining such agreements or establishing new ones could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
The electric generation and wholesale power sales industries are highly competitive. As more plants are built, supplies of energy and related products may exceed demand, competitive pressures may increase and wholesale electricity prices may decline or become more volatile. Without long-term power sales agreements, our revenues may be subject to increased volatility, and we may be unable to sell the power that SI Partners’ facilities can produce at favorable prices or at all, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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We rely on transportation assets and services, much of which we do not control, to deliver natural gas and electricity.
We depend on electric transmission lines, natural gas pipelines and other transportation facilities and services owned and operated by third parties to, among other things:
▪ deliver the natural gas, LNG, electricity and LPG we sell to customers or use at our LNG facilities
▪ supply natural gas to our gas storage and electric generation facilities
▪ provide retail energy services to customers
If transportation is disrupted, the construction of necessary interconnecting infrastructure is not completed on schedule or at all or capacity is inadequate, we may be delayed in completing projects under development and/or unable to meet our contractual obligations to customers of those projects or existing projects, in which case we may be responsible for damages they incur, such as the cost of acquiring alternative supplies at then-current spot market rates, and we could lose customers that may be difficult to replace. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Financial Risks
Fixed-price long-term contracts for services or commodities expose our businesses to risks.
SI Partners seeks long-term contracts for services and commodities to better utilize its facilities, reduce volatility in earnings and support the construction of new infrastructure. Certain of these contracts are at fixed prices, and their profitability may be negatively affected by inflation, tariffs, rising interest rates and changes in applicable exchange rates. We aim to mitigate these risks by, among other things, using variable pricing tied to market indices, contracting for direct pass-through of operating costs and/or entering into hedges. However, these measures may not fully or substantially offset any increases in operating expenses or financing costs and their use could introduce additional risks, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Our international businesses and operations expose us to foreign currency exchange rate and inflation risks.
Our operations in Mexico pose foreign currency exchange rate and inflation risks. Exchange and inflation rates with respect to Mexico and fluctuations in those rates may have an impact on the revenue, cash flows and costs from our international operations, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We sometimes attempt to hedge cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments, but these hedges may not fully achieve our objectives of mitigating earnings volatility that would otherwise occur due to exchange rate fluctuations. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations for entities whose functional currencies are not the U.S. dollar. Moreover, Mexico has experienced periods of high inflation and exchange rate instability in the past, and severe devaluation of the Mexican peso could result in governmental intervention to institute restrictive exchange control policies, as has occurred in Mexico and other Latin American countries. We discuss our foreign currency exposure at our Mexican subsidiaries in “Part II – Item 7. MD&A” and “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Our businesses are exposed to fluctuations in commodity prices.
We buy energy-related commodities from time to time for pipeline operations, LNG facilities or power plants to satisfy contractual obligations with customers. The regional and other markets in which we purchase these commodities are competitive and can be subject to significant pricing volatility. Our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities we buy change in a direction or manner not anticipated and for which we have not provided adequately through purchase or sale commitments or other hedging transactions.
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.
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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.
Legal and Regulatory Risks
Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical, credit and management oversight risks and challenges.
We own or have interests in a variety of energy infrastructure assets in Mexico, and we do business with companies based in foreign markets, including particularly our LNG export operations. Conducting these activities in foreign jurisdictions subjects us to complex management, security, political, legal, economic and financial risks that vary by country, many of which may differ from and potentially be greater than those associated with our wholly domestic businesses, and the occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. These risks include the following and the other risks discussed in this risk factor below:
▪ compliance with tax, trade, environmental and other foreign laws and regulations, including legal limitations on ownership in some foreign countries and inadequate or inconsistent enforcement of regulations
▪ actions by local regulatory bodies, such as the CNE, including setting rates and tariffs that may be earned by or charged to our businesses
▪ adverse changes in social, geopolitical, economic or market conditions
▪ adverse rulings by or instability in foreign courts or tribunals
▪ challenges obtaining, maintaining and complying with permits or approvals
▪ difficulty enforcing contractual and property rights and differing legal standards
▪ expropriation or theft of assets
▪ the stability of foreign governments or such foreign governments’ relations with the U.S. government
▪ changes in the priorities and budgets of international customers, which may be driven by many of the factors listed above, among others
Mexican Government Influence on Economic and Energy Matters
The Mexican government exercises significant and increasing influence over the Mexican energy sector and has adopted additional changes that could impact private investment in this sector.
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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Although the new laws, regulations, and certain general administrative provisions in the energy sector have been published, the extent of the impact of the 2025 Energy Laws remains uncertain. These laws and future implementation of existing and any new regulations could adversely affect SI Partners’ ability to secure favorable rate cases and operate its existing assets at their current levels; result in increased costs to SI Partners and its customers; adversely impact SI Partners’ ability to secure and retain permits and develop new projects in Mexico; result in decreased revenues and/or cash flows; and negatively impact SI Partners’ ability to recover the carrying values of its investments in Mexico, any of which could have a material adverse impact on our business, results of operations, financial condition, cash flow and/or prospects.
In addition to the constitutional changes noted above, in 2024 the Mexican government introduced significant changes to the Mexican Constitution, including reforms requiring that all judges be elected rather than appointed, which may adversely impact, among other things, SI Partners’ ability to enforce its contracts with state-owned enterprises or challenge actions taken by regulators. These reforms and any further Mexican Constitutional, legal or regulatory changes could adversely affect the Mexican economy, energy sector and our businesses, the extent of which we currently are unable to predict.
U.S. and Foreign Laws and International Relations
Our international business activities are subject to laws and regulations in the U.S. and Mexico and other countries where we do business related to foreign operations and doing business internationally, including the U.S. Foreign Corrupt Practices Act, the Mexican Federal Anticorruption Law in Public Contracting (Ley Federal Anticorrupción en Contrataciones Públicas) and similar laws, and are sensitive to geopolitical factors in each of these countries. The current and the last U.S. Administrations have taken different stances with respect to international trade agreements, tariffs, immigration and other matters of foreign policy that impact trade and foreign relations. We discuss developments in tariff policies above under “Risks Related to All Sempra Businesses – Operational Risks.” Shifts in other aspects of foreign policy could create uncertainty and result in or increase adverse effects on our businesses. Violations or allegedviolations of the laws referred to above, as well as foreign policy positions or sanctions, could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We face risks related to unsettled property rights and titles in Mexico.
We are engaged in a dispute regarding our title to property in Mexico adjacent to and owned by the ECA Regas Facility, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. In addition, we have and may in the future seek to obtain long-term leases or rights-of-way from governmental agencies or other third parties to operate our energy infrastructure on land we do not own. In addition to the risks associated with such property ownership and use that we describe above under “Risks Related to All Sempra Businesses – Operational Risks,” disputes regarding ownership or rights to any of these properties could lead to difficulties developing, constructing and, if completed, operating the affected facilities or proposed projects. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
SI Partners’ energy infrastructure assets may be considered by the Mexican government to be a public service or essential for the provision of a public service, in which case these assets and the related businesses could be subject to expropriation or nationalization, loss of concessions, renegotiation or annulment of existing contracts, and other similar risks. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
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Risk Related to Planned Sales of Certain Assets and Businesses
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.
Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
CYBERSECURITY RISK MANAGEMENT
Sempra, SDG&E and SoCalGas have cybersecurity risk management processes in place that are intended to protect the confidentiality, integrity, and availability of our critical infrastructure, systems and information. These cybersecurity risk management processes include cybersecurity incident response plans that are integrated into each entity’s respective enterprise risk management and emergency management programs.
Our cybersecurity processes are largely designed and assessed based on the National Institute of Standards and Technology Cybersecurity Framework and the DOE’s Cybersecurity Capability Maturity Model standards. This does not imply that we meet any technical standards, specifications, or requirements, only that we use these standards as a guide to help us identify, assess, and manage cybersecurity risks relevant to our business.
▪ risk assessments performed by internal personnel and third-party advisors designed to help identify material cybersecurity risks to our critical systems, information, services, and our broader enterprise information technology environments
▪ cybersecurity teams principally responsible for developing and implementing (1) cybersecurity risk assessment processes, (2) cybersecurity controls, and (3) response plans to cybersecurity incidents
▪ the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our cybersecurity controls
▪ cybersecurity awareness training and policies designed to address social engineering attacks targeting employees and contractors
▪ cybersecurity incident response plans that include procedures for responding to and reporting, if applicable, certain cybersecurity incidents
▪ risk management processes for third-party service providers, suppliers, and vendors
We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected or are reasonably likely to materially affect our results of operations, financial condition, cash flows and/or prospects.
CYBERSECURITY GOVERNANCE
Sempra’s, SDG&E’s and SoCalGas’ respective boards of directors consider cybersecurity risk as part of their risk oversight function. The Sempra board of directors has delegated to its SST Committee oversight of cybersecurity and other information and operational technology risks. The SST Committee reports to the Sempra board of directors regarding the Committee’s activities, including those related to cybersecurity. The SST Committee receives briefings on cybersecurity topics from Sempra’s chief information security officer, internal information technology leadership or external experts in part for continuing education on topics that impact public companies. The SST Committee as well as the SDG&E and SoCalGas boards of directors oversee management’s implementation of our cybersecurity risk management processes and receive regular reports from management on our material cybersecurity risks. In addition, as needed, management updates the SST Committee and SDG&E and SoCalGas boards of directors about certain cybersecurity incidents. The SDG&E and SoCalGas boards of directors receive briefings from SDG&E’s and SoCalGas’ chief information officer and internal information technology and cybersecurity leadership. SDG&E’s and SoCalGas’ boards of directors also have safety committees that, at times, may oversee the matters described above on behalf of those companies’ respective boards of directors.
We have formed cybersecurity councils to provide overall corporate oversight for managing material risks from cybersecurity threats. The cybersecurity councils meet regularly to receive updates on cybersecurity developments at Sempra and our consolidated entities from their cybersecurity management teams.
Our cybersecurity management teams supervise efforts designed to prevent, detect, mitigate, and remediate cybersecurity risks and incidents. The cybersecurity management teams receive intelligence on emerging cybersecurity threats through various means, including internal cybersecurity personnel; governmental, public and private sources; subject matter experts and consultants; and cybersecurity tools deployed in the environment. Cybersecurity management also supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Sempra’s director of cybersecurity governance & chief information security officer provides additional oversight and support for the operational cybersecurity activities at our consolidated entities.
Our cybersecurity materiality assessment teams, which include chief information security officers, chief information officers, chief accounting officers or chief financial officers, and general counsels, help assess the materiality of certain cybersecurity incidents.
The cybersecurity management teams, cybersecurity councils and materiality assessment teams include professionals with decades of experience in their respective fields of cybersecurity, information and operational technology, legal, compliance, financial reporting and enterprise risk management. Some of these professionals hold relevant degrees and certifications that we believe enhance our ability to manage and respond to cybersecurity risks, including, among others, bachelor’s and/or master’s degrees in cybersecurity and computer science as well as certified information systems security professional, certified incident handler, and certified information security manager certifications .
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ITEM 2. PROPERTIES
We own or lease land, warehouses, offices, operating and maintenance centers, shops and service facilities necessary to conduct our businesses. Each of the Registrants currently has adequate space and, if we need more space, we believe it is readily available. We discuss properties related to our electric, natural gas and energy infrastructure operations in “Part I – Item 1. Business” and Note 1 of the Notes to Consolidated Financial Statements.
ITEM 3. LEGAL PROCEEDINGS
We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses), including environmental proceedings described in Item 103(c)(3) of SEC Regulation S-K, except for the matters described in Note 16 of the Notes to Consolidated Financial Statements or referred to in “Part I – Item 1A. Risk Factors” or “Part II – Item 7. MD&A.”
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION
Sempra Common Stock
Our common stock is traded on the NYSE under the trading symbol SRE. At February 19, 2026, there were approximately 18,180 record holders of our common stock. Information concerning dividend declarations for Sempra is included in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”
SoCalGas and SDG&E Common Stock
Information concerning dividend declarations for SoCalGas and SDG&E is included in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $2 billion or amounts spent to purchase no more than 25,000,000 shares. This repurchase authorization was publicly announced on August 5, 2020 and has no expiration date. As of February 26, 2026, a maximum of $1.25 billion and no more than 19,632,529 shares may yet be purchased under this repurchase authorization.
ITEM 6. (RESERVED)
Not applicable.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Page
Overview
Results of Operations by Registrant
Sempra
SDG&E
SoCalGas
Capital Resources and Liquidity
Critical Accounting Estimates
New Accounting Standards
OVERVIEW
This combined MD&A includes the operational and financial results of the following three Registrants:
▪ Sempra is a holding company whose principal businesses are regulated utilities in California and Texas. Our businesses invest in and operate electric and gas utilities and other energy infrastructure that provide energy services to customers.
▪ SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
▪ SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
Sempra has the following three reportable segments which reflect how the CODM oversees operational and financial performance:
▪ Sempra California
▪ Sempra Texas Utilities
▪ Sempra Infrastructure
SDG&E and SoCalGas each have one reportable segment.
Below are significant events, including major project updates, that affected our business in 2025 and may continue to affect our future results:
▪ The 2025 Wildfire Legislation was signed into law and established, among other things, an $18 billion Continuation Account that would provide additional liquidity to reimburse catastrophic wildfire-related claims incurred by large California electric IOUs if the Wildfire Fund is depleted, and 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
▪ The CPUC issued an FD for SDG&E’s and SoCalGas’ cost of capital for 2026 through 2028
▪ The CPUC issued an FD in SDG&E’s 2024 GRC Track 2 request that authorizes partial recovery of SDG&E’s WMP costs
▪ Oncor filed its 2025 comprehensive base rate review and expects to receive a final order from the PUCT in the first half of 2026
▪ In June 2025, Texas House Bill 5247, which established the UTM, was signed into law and became effective
▪ In September 2025, we entered into an agreement to sell 45% of our equity interest in SI Partners to the KKR Partners for an aggregate base purchase price of approximately $9.99 billion, subject to adjustments, and expect the sale to close in the second or third quarter of 2026, subject to closing conditions
▪ In December 2025, we entered into an agreement to sell Ecogas for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments, and expect the sale to close in the second or third quarter of 2026, subject to closing conditions
▪ We sold a 49.9% equity interest in the PA LNG Phase 2 project to Blackstone
▪ SI Partners reached a positive FID on the PA LNG Phase 2 project and issued a full notice-to-proceed under Bechtel’s fixed-price EPC contract
▪ We invested $12.6 billion in capital expenditures and investments
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RESULTS OF OPERATIONS BY REGISTRANT
Throughout this MD&A, our references to earnings represent earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates unless otherwise noted) and after NCI but before foreign currency and inflation effects, where applicable.
We discuss herein Sempra’s results of operations and significant changes in earnings, revenues and costs by segment, as well as Parent and other, for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of our results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Results of Operations ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025. We also discuss herein the impact of foreign currency and inflation rates on Sempra’s results of operations.
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
(Dollars and shares in millions, except per share amounts)
EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
Years ended December 31,
Sempra:
Sempra California
Sempra Texas Utilities
Sempra Infrastructure
Segment earnings attributable to common shares
Parent and other
Earnings attributable to common shares
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Sempra California
Sempra California’s earnings are comprised of SDG&E and SoCalGas. Because changes in SDG&E’s and SoCalGas’ cost of natural gas and/or electricity are recovered in rates, changes in these costs are offset in the changes in revenues and therefore do not impact earnings, other than potential impacts related to the GCIM for SoCalGas that we describe below. In addition to the changes in cost or market prices, natural gas or electric revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized amounts. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 4 of the Notes to Consolidated Financial Statements.
In 2025 compared to 2024, the decrease in earnings of $418 million (23%) was primarily due to:
▪ $432 million charge in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD, which we discuss in Note 4 of the Notes to Consolidated Financial Statements
▪ $159 million lower income tax benefits primarily from flow-through items, including gas repairs tax benefits, offset by impacts from the election to accelerate self-developed software deductions and the resolution of prior year income tax items
▪ $63 million higher net interest expense
▪ $25 million charge in 2025 from disallowed regulatory recovery of COVID-19 costs
Offset by:
▪ $148 million higher CPUC base operating margin, net of operating expenses including higher depreciation, $44 million lower authorized cost of capital and a $32 million charge from regulatory disallowances associated with the 2024 GRC Track 2 FD related to 2025
▪ $89 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019
▪ $15 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD
Sempra Texas Utilities
In 2025 compared to 2024, the increase in earnings of $80 million (10%) was primarily due to higher equity earnings from Oncor Holdings driven by:
▪ overall higher revenues primarily attributable to:
◦ the establishment of the UTM
◦ rate updates to reflect increases in invested capital
◦ customer growth
◦ higher annual energy efficiency program performance bonus
Offset by:
▪ higher interest expense and depreciation expense associated with increases in invested capital
▪ higher O&M
Sempra Infrastructure
In 2025 compared to 2024, losses were $160 million compared to earnings of $911 million primarily due to:
▪ $703 million income tax expense in 2025 as a result of management’s decision to classify SI Partners and Ecogas as held for sale, comprised of the following:
◦ $693 million income tax expense to adjust deferred income tax liabilities primarily related to outside basis differences in our investment in SI Partners
◦ $10 million income tax expense due to the recognition of a deferred tax liability on our outside basis difference in Ecogas
▪ $445 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $181 million unfavorable impact in 2025 compared to a $264 million favorable impact in 2024
▪ $43 million lower income tax benefit primarily from outside basis differences and the remeasurement of certain deferred income taxes
▪ $30 million unfavorable impact in interest expense from unrealized gains in 2024 on interest rate swaps related to the PA LNG Phase 1 project
▪ $27 million unfavorable impact related to a customer’s early termination of firm transportation agreements, including interest expense
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▪ $21 million from TdM driven by lower volumes and lower power prices and unrealized losses in 2025 compared to unrealized gains in 2024 on commodity derivatives due to changes in power prices
Offset by:
▪ $52 million from asset and supply optimization driven by higher optimization of transport and storage contracts, higher LNG diversion fees and lower unrealized losses on commodity derivatives due to changes in natural gas prices
▪ $38 million lower O&M in 2025 primarily from lower provisions for expected credit losses
▪ $37 million lower depreciation expense as a result of management's decision to classify SI Partners and Ecogas as held for sale
▪ $31 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement that ended in December 2025
▪ $13 million higher net interest income primarily from a change in the fair value of the Support Agreement
Parent and Other
In 2025 compared to 2024, the decrease in losses of $388 million was primarily due to:
▪ $252 million from $78 million income tax expense in 2025 compared to $330 million income tax expense in 2024 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA
▪ $191 million net income tax benefit in 2025 from changes to a valuation allowance against certain tax credit carryforwards offset by changes in state income tax apportionment as a result of management’s decision to classify SI Partners as held for sale
▪ $22 million income tax benefit in 2025 from the impacts of the OBBBA
▪ $19 million higher net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan
▪ $15 million lower preferred dividends
Offset by:
▪ $92 million higher net interest expense
▪ $16 million equity earnings in 2024 related to our investment in RBS Sempra Commodities LLP from the substantial dissolution of the partnership
▪ $11 million preferred deemed dividends related to the redemption of series C preferred stock in 2025
SIGNIFICANT CHANGES IN REVENUES AND COSTS
The regulatory framework permits SDG&E and SoCalGas to recover certain program expenditures and other costs authorized by the CPUC (referred to as “refundable programs”), which may be subject to reviews for reasonableness.
Utilities: Natural Gas Revenues and Cost of Natural Gas
Our utilities revenues include natural gas revenues at Sempra California and Sempra Infrastructure, which includes Ecogas. Intercompany revenues are eliminated in Sempra’s Consolidated Statements of Operations.
SDG&E and SoCalGas operate under a regulatory framework that permits the cost of natural gas purchased for core customers to be passed through to customers in rates substantially as incurred and without markup. The GCIM provides for SoCalGas to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between SoCalGas and its core customers. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements.
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UTILITIES: NATURAL GAS REVENUES AND COST OF NATURAL GAS
(Dollars in millions)
Years ended December 31,
Sempra:
Natural gas revenues:
Sempra California
Sempra Infrastructure
Segment totals
Eliminations and adjustments
Total
Cost of natural gas (1) :
Sempra California
Sempra Infrastructure
Segment totals
Eliminations and adjustments
Total
(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.
In 2025 compared to 2024, Sempra’s natural gas revenues increased by $178 million (2%) driven by Sempra California, which included:
▪ $202 million higher CPUC-authorized base revenues, net of $40 million lower authorized cost of capital
▪ $146 million increase in cost of natural gas sold, which we discuss below
▪ $88 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital
▪ $18 million higher regulatory revenues associated with refundable programs, which are fully offset in O&M
Offset by:
▪ $166 million lower regulatory revenues primarily from the release of a regulatory liability in 2024 for gas repairs tax benefits as a result of the 2024 GRC FD
▪ $57 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax expense
▪ $29 million lower revenues in 2025 from disallowed regulatory recovery of COVID-19 costs
In 2025 compared to 2024, Sempra’s cost of natural gas increased by $150 million (13%) driven by Sempra California, which included:
▪ $193 million higher average natural gas prices
Offset by:
▪ $47 million lower volumes driven by weather
Utilities: Electric Revenues and Cost of Electric Fuel and Purchased Power
Our utilities revenues include electric revenues at Sempra California, substantially all of which are at SDG&E. Intercompany revenues are eliminated in Sempra’s Consolidated Statements of Operations.
SDG&E operates under a regulatory framework that permits it to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered or refunded in subsequent periods through rates.
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Utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to/from the California ISO.
UTILITIES: ELECTRIC REVENUES AND COST OF ELECTRIC FUEL AND PURCHASED POWER
(Dollars in millions)
Years ended December 31,
Sempra:
Electric revenues:
Sempra California
Eliminations and adjustments
Total
Cost of electric fuel and purchased power (1) :
Sempra California
Eliminations and adjustments
Total
(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.
In 2025 compared to 2024, Sempra’s electric revenues increased by $256 million (6%) driven by Sempra California, which included:
▪ $140 million increase in cost of electric fuel and purchased power, which we discuss below
▪ $94 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019
▪ $80 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital
▪ $36 million higher CPUC-authorized base revenues, net of $20 million lower authorized cost of capital
▪ $31 million higher revenues from transmission operations
▪ $22 million higher revenues from a $17 million cost in 2025 compared to a $5 million credit in 2024 for the non-service components of net periodic benefit cost, which fully offsets in other income, net
Offset by:
▪ $115 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax expense
▪ $23 million lower regulatory revenues associated with refundable programs, which are fully offset in O&M
▪ $21 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax expense
In 2025 compared to 2024, Sempra’s cost of electric fuel and purchased power increased by $140 million driven by Sempra California, which included:
▪ $151 million higher purchased power primarily due to changes in excess capacity sales and tolling agreements
▪ $55 million lower sales to the California ISO due to lower market prices
Offset by:
▪ $62 million lower purchased power from the California ISO due to lower market prices and lower customer demand from departing load now served by CCAs
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Energy-Related Businesses: Revenues and Cost of Sales
ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
Years ended December 31,
Sempra:
Revenues:
Sempra Infrastructure
Parent and other (1)
Total
Cost of sales (2) :
Sempra Infrastructure
Total
(1) Includes eliminations of intercompany activity.
(2) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.
In 2025 compared to 2024, Sempra’s revenues from energy-related businesses increased by $83 million (5%) primarily due to:
▪ $63 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement that ended in December 2025
▪ $59 million from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
◦ $54 million primarily from higher diversion fees due to higher natural gas prices
◦ $36 million driven by higher natural gas prices and higher volumes associated with optimization of transport and storage contracts
Offset by:
◦ $31 million higher unrealized losses on commodity derivatives
▪ $15 million higher revenues in 2025 due to the commencement of commercial operations at the Topolobampo marine terminal in June 2024
Offset by:
▪ $30 million lower transportation revenues driven by a customer’s early termination of firm transportation agreements
▪ $14 million from TdM mainly due to lower volumes and lower power prices
In 2025 compared to 2024, Sempra’s cost of sales from energy-related businesses decreased by $13 million (3%) primarily due to:
▪ $27 million driven by lower LNG purchases offset by higher natural gas purchases related to asset and supply optimization
Offset by:
▪ $10 million higher purchased power due to higher power capacity sales
Operation and Maintenance
OPERATION AND MAINTENANCE
(Dollars in millions)
Years ended December 31,
Sempra:
Sempra California
Sempra Texas Utilities
Sempra Infrastructure
Segment totals
Parent and other (1)
Total
(1) Includes eliminations of intercompany activity.
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In 2025 compared to 2024, Sempra’s O&M decreased by $55 million (1%) primarily due to:
▪ $83 million decrease at Sempra California due to:
◦ $61 million lower non-refundable operating costs
◦ $20 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD
◦ $5 million lower expenses associated with refundable programs, which costs are recovered in revenue
Offset by:
▪ $20 million increase at Parent and other primarily due to non-recoverable insurance claims in 2025
▪ $7 million increase at Sempra Infrastructure due to:
◦ $42 million primarily due to higher maintenance expenses and higher expenses in 2025 in advance of ECA LNG Phase 1 commencing commercial operations
◦ $38 million higher development costs and certain non-capitalized expenses from projects under construction
Offset by:
◦ $73 million lower provisions for expected credit losses
Regulatory Disallowances
As we discuss in Note 4 of the Notes to Consolidated Financial Statements, the CPUC issued an FD in SDG&E’s 2024 GRC Track 2 request that disallowed recovery of certain WMP costs. In connection with the Track 2 FD, in the fourth quarter of 2025, SDG&E recorded a charge of $651 million ($464 million after tax), of which:
▪ $605 million ($432 million after tax) relates to 2019 through 2024
▪ $41 million ($28 million after tax) relates to the first nine months of 2025
▪ $5 million ($4 million after tax) relates to the fourth quarter of 2025
Depreciation and Amortization
In 2025 compared to 2024, Sempra’s depreciation and amortization increased by $126 million (5%) to $2.6 billion primarily due to:
▪ $199 million higher at Sempra California due to higher utility plant rate base
Offset by:
▪ $71 million lower at Sempra Infrastructure due to:
◦ $81 million lower as a result of management's decision to classify SI Partners and Ecogas as held for sale
Offset by:
◦ $11 million higher due to the commencement of commercial operations at Gasoducto Rosarito pipeline expansion in December 2024 and Topolobampo marine terminal in June 2024
Other Income, Net
In 2025 compared to 2024, Sempra’s other income, net, increased by $33 million (24%) to $169 million primarily due to:
▪ $26 million charge in 2024, comprised of $7 million of AFUDC equity and $19 million of net regulatory interest, relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019
▪ $25 million from $11 million gains in 2025 compared to $14 million losses in 2024 driven by foreign currency transactional effects primarily at Sempra Infrastructure
▪ $17 million higher AFUDC equity primarily at Sempra Infrastructure
▪ $16 million higher net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other
Offset by:
▪ $41 million higher non-service components of net periodic benefit cost primarily at Sempra California
▪ $7 million reduction in regulatory interest in 2025 from disallowed regulatory recovery of COVID-19 costs at Sempra California
We provide further details of the components of other income, net, in Note 1 of the Notes to Consolidated Financial Statements.
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Interest Income
In 2025 compared to 2024, Sempra’s interest income increased by $42 million to $103 million primarily due to:
▪ $33 million higher interest from interest bearing cash accounts primarily at Sempra Infrastructure
▪ $14 million change in the fair value of the Support Agreement at Sempra Infrastructure
Interest Expense
In 2025 compared to 2024, Sempra’s interest expense increased by $483 million (46%) to $1.5 billion primarily due to:
▪ $271 million at Sempra Infrastructure from:
◦ $241 million unfavorable impact in interest expense from interest rate swaps related to the PA LNG Phase 1 project comprised of:
• $215 million from $3 million unrealized losses in 2025 compared to $212 million unrealized gains in 2024
• $29 million settlement in 2024 from the termination of interest rate swaps
◦ $17 million higher interest expense related to a customer’s early termination of firm transportation agreements
▪ $134 million at Parent and other from higher debt balances from debt issuances offset by higher capitalization of interest expense in 2025 from projects under construction at Sempra Infrastructure
▪ $78 million at Sempra California from higher debt balances from debt issuances
Income Taxes
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Years ended December 31,
Sempra:
Income tax expense
Income from continuing operations before income taxes and equity earnings
Equity earnings, before income tax (1)
Pretax income
Effective income tax rate
(1) We discuss how we recognize equity earnings in Note 5 of the Notes to Consolidated Financial Statements.
We report as part of our pretax results the income or loss attributable to NCI. However, we do not record income taxes for a portion of this income or loss, as some of our entities with NCI are currently treated as partnerships for U.S. income tax purposes, and thus we are only liable for income taxes on the portion of the earnings that are allocated to us. Our pretax income, however, includes 100% of these entities. If our entities with NCI grow, and if we continue to invest in such entities, the impact on our ETR may become more significant.
In 2025 compared to 2024, Sempra’s income tax expense increased by $482 million primarily due to:
▪ $576 million from $240 million income tax expense in 2025 compared to $336 million income tax benefit in 2024 from foreign currency and inflation effects on our monetary positions in Mexico
▪ $516 million net income tax expense in 2025 as a result of management’s decision to classify SI Partners and Ecogas as held for sale, comprised of the following:
◦ $693 million income tax expense to adjust deferred income tax liabilities primarily related to outside basis differences in our investment in SI Partners
◦ $153 million income tax expense for changes in state income tax apportionment
◦ $14 million income tax expense due to the recognition of a Mexican deferred tax liability on our outside basis differences in Ecogas
Offset by:
◦ $344 million income tax benefit from changes to a valuation allowance against certain tax credit carryforwards
▪ $30 million income tax benefit in 2024 from an outside basis difference in a domestic partnership investment
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Offset by:
▪ $252 million from $78 million income tax expense in 2025 compared to $330 million income tax expense in 2024 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA
▪ $173 million income tax benefit in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD
▪ lower pretax income
▪ higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
▪ higher income tax benefit from flow-through items, including $73 million income tax benefit in 2025 from the election to accelerate self-developed software deductions
We discuss the impact of foreign currency exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Notes 1 and 8 of the Notes to Consolidated Financial Statements for further details about our accounting for income taxes and items subject to flow-through treatment.
Equity Earnings
In 2025 compared to 2024, Sempra’s equity earnings decreased by $5 million remaining at $1.6 billion primarily due to:
▪ $93 million at IMG due to an income tax expense in 2025 compared to an income tax benefit in 2024 primarily from foreign currency and inflation effects
▪ $19 million in 2024 related to our investment in RBS Sempra Commodities LLP from the substantial dissolution of the partnership
Offset by:
▪ $82 million at Oncor Holdings driven by:
◦ overall higher revenues primarily attributable to:
• the establishment of the UTM
• rate updates to reflect increases in invested capital
• customer growth
• higher annual energy efficiency program performance bonus
Offset by:
◦ higher interest expense and depreciation expense associated with increases in invested capital
◦ higher O&M
▪ $37 million at Cameron LNG JV primarily from lower interest expense, higher revenues from excess LNG and higher maintenance revenues
Earnings Attributable to Noncontrolling Interests
In 2025 compared to 2024, Sempra’s earnings attributable to NCI decreased by $400 million to $238 million primarily due to a decrease in SI Partners subsidiaries’ net income driven by foreign currency and inflation effects on our monetary positions in Mexico and unrealized losses in 2025 compared to unrealized gains in 2024 from interest rate swaps related to the PA LNG Phase 1 project.
IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS
Because Ecogas, our natural gas distribution utility in Mexico, uses the Mexican peso as its functional currency, its revenues and expenses are translated into U.S. dollars at average exchange rates for the period when included in Sempra’s results of operations. Year‑over‑year differences in average exchange rates used to translate Ecogas’ income statement activity can therefore create variances in our comparative results of operations. In 2025 compared to 2024, the impact of changes in average foreign currency translation rates on our earnings was $1 million.
Although the functional currency for most of our Mexican subsidiaries and equity method investees is the U.S. dollar, certain transactions are denominated in the local currency. These local currency transactions are remeasured into U.S. dollars, which results in transactional gains and losses recognized in other income, net, for consolidated entities and in equity earnings for equity method investments.
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We may utilize cross-currency swaps to convert Mexican peso-denominated principal and interest payments into U.S. dollars and swap Mexican fixed interest rates for U.S. fixed interest rates. The effects of these cross-currency swaps are initially recorded in OCI and are reclassified from AOCI into earnings through other income, net, and interest expense as settlements occur.
Certain of our Mexican pipelines (namely Los Ramones I and San Fernando at IEnova Pipelines and Los Ramones Norte at TAG Pipelines) generate revenue based on government-regulated tariffs with contracts denominated in Mexican pesos that are indexed to the U.S. dollar and adjusted annually for inflation and exchange rate movements. As a result, remeasurement of these peso-denominated amounts into U.S. dollars gives rise to foreign currency gains and losses. These impacts, together with the offsetting gains and losses from the settlement of related foreign currency forwards and swaps, are recorded in revenues: energy-related businesses or equity earnings.
In addition, our Mexican subsidiaries hold U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that are subject to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have significant deferred income tax assets and liabilities denominated in Mexican pesos that must be translated into U.S. dollars for financial reporting. Moreover, Mexican tax law requires monetary assets and liabilities and certain nonmonetary assets and liabilities to be adjusted for inflation. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation can cause volatility in income tax expense, other income, net, and equity earnings. We may use foreign currency derivatives to help manage exposure to exchange rate movements on monetary assets and liabilities, with derivative impacts reflected in other income, net. However, we generally do not hedge our deferred income tax assets and liabilities, which makes us susceptible to volatility in income tax expense caused by exchange rate and inflationary changes.
The impact from fluctuations in foreign currency exchange rates and Mexican inflation on our results of operations is summarized in the following table.
TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION EFFECTS
(Dollars in millions)
Total reported amounts
Transactional
gains (losses) included
in reported amounts
Years ended December 31,
Sempra:
Other income, net
Income tax expense
Equity earnings
Net income
Earnings attributable to noncontrolling interests
Earnings attributable to common shares
At December 31, 2025, SI Partners, which holds our foreign operations, is classified as held for sale. Upon completion of the sale, which we expect to occur in the second or third quarter of 2026, we will deconsolidate SI Partners and account for our remaining 25% interest under the equity method, thereby reducing volatility in our results of operations associated with foreign currency exchange rate fluctuations and Mexican inflation.
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We discuss herein SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Results of Operations ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025.
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
(Dollars in millions)
In 2025 compared to 2024, the decrease in SDG&E’s earnings of $328 million (37%) was primarily due to:
▪ $432 million charge in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD, which we discuss in Note 4 of the Notes to Consolidated Financial Statements
▪ $29 million higher net interest expense
▪ $13 million lower income tax benefits primarily from flow-through items, including gas repairs tax benefits offset by the impacts from the election to accelerate self-developed software deductions
Offset by:
▪ $89 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019
▪ $33 million higher CPUC base operating margin, net of operating expenses including higher depreciation, $32 million charge from regulatory disallowances associated with the 2024 GRC Track 2 FD related to 2025 and $19 million lower authorized cost of capital
▪ $12 million higher net regulatory interest income
▪ $6 million higher electric transmission margin
SIGNIFICANT CHANGES IN REVENUES AND COSTS
Electric Revenues and Cost of Electric Fuel and Purchased Power
In 2025 compared to 2024, SDG&E’s electric revenues increased by $255 million (6%) to $4.6 billion primarily due to:
▪ $140 million increase in cost of electric fuel and purchased power, which we discuss below
▪ $94 million charge in 2024 for amounts relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019
▪ $80 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital
▪ $36 million higher CPUC-authorized base revenues, net of $20 million lower authorized cost of capital
▪ $31 million higher revenues from transmission operations
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▪ $22 million higher revenues from a $17 million cost in 2025 compared to a $5 million credit in 2024 for the non-service components of net periodic benefit cost, which fully offsets in other income, net
Offset by:
▪ $115 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax benefit (expense)
▪ $23 million lower regulatory revenues associated with refundable programs, which are fully offset in O&M
▪ $21 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)
In 2025 compared to 2024, SDG&E’s cost of electric fuel and purchased power increased by $140 million (45%) to $448 million primarily due to:
▪ $151 million higher purchased power primarily due to changes in excess capacity sales and tolling agreements
▪ $55 million lower sales to the California ISO due to lower market prices
Offset by:
▪ $62 million lower purchased power from the California ISO due to lower market prices and lower customer demand from departing load now served by CCAs
Natural Gas Revenues and Cost of Natural Gas
SDG&E’s average cost of natural gas per thousand cubic feet was $5.40 in 2025 and $5.41 in 2024. The average cost of natural gas sold at SDG&E is impacted by market prices, as well as transportation, tariff and other charges.
In 2025 compared to 2024, SDG&E’s natural gas revenues increased by $101 million (10%) to $1.1 billion primarily due to:
▪ $62 million higher regulatory revenues associated with refundable programs, which are fully offset in O&M
▪ $40 million higher CPUC-authorized base revenues, net of $6 million lower authorized cost of capital
▪ $29 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital
Offset by:
▪ $37 million lower regulatory revenues primarily from the release of a regulatory liability in 2024 for gas repairs tax benefits as a result of the 2024 GRC FD
Operation and Maintenance
In 2025 compared to 2024, SDG&E’s O&M increased by $33 million (2%) remaining at $1.7 billion primarily due to:
▪ $39 million higher expenses associated with refundable programs, which costs are recovered in revenue
Offset by:
▪ $9 million lower non-refundable operating costs
Regulatory Disallowances
As we discuss in Note 4 of the Notes to Consolidated Financial Statements, the CPUC issued an FD in SDG&E’s 2024 GRC Track 2 request that disallowed recovery of certain WMP costs. In connection with the Track 2 FD, in the fourth quarter of 2025, SDG&E recorded a charge of $651 million ($464 million after tax), of which:
▪ $605 million ($432 million after tax) relates to 2019 through 2024
▪ $41 million ($28 million after tax) relates to the first nine months of 2025
▪ $5 million ($4 million after tax) relates to the fourth quarter of 2025
Other Income, Net
In 2025 compared to 2024, SDG&E’s other income, net, increased by $16 million (18%) to $106 million primarily due to:
▪ $26 million charge in 2024, comprised of $7 million of AFUDC equity and $19 million of net regulatory interest, relating to the FERC order finding that the TO5 adder refund provision has been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019
▪ $17 million higher net interest income on regulatory balancing accounts
Offset by:
▪ $31 million decrease from a $27 million cost in 2025 compared to $4 million credit in 2024 for the non-service components of net periodic benefit cost
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Income Taxes
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Years ended December 31,
SDG&E:
Income tax (benefit) expense
Income before income taxes
Effective income tax rate
In 2025 compared to 2024, SDG&E had an income tax benefit in 2025 compared to income tax expense in 2024 primarily due to:
▪ $173 million income tax benefit in 2025 from regulatory disallowances related to 2019 through 2024 associated with the 2024 GRC Track 2 FD
▪ higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
▪ higher income tax benefit from flow-through items, including $26 million income tax benefit in 2025 from the election to accelerate self-developed software deductions, which we discuss in Note 8 of the Notes to Consolidated Financial Statements
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We discuss herein SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Results of Operations ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025.
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
(Dollars in millions)
In 2025 compared to 2024, the decrease in SoCalGas’ earnings of $90 million (9%) was primarily due to:
▪ $146 million lower income tax benefits primarily from flow-through items including gas repairs tax benefits, offset by the resolution of prior year income tax items and impacts from the election to accelerate self-developed software deductions
▪ $34 million higher net interest expense
▪ $25 million charge in 2025 from disallowed regulatory recovery of COVID-19 costs
▪ $8 million lower net regulatory interest income
▪ $6 million lower regulatory award approved by the CPUC
Offset by:
▪ $115 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $25 million lower authorized cost of capital
▪ $15 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD
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SIGNIFICANT CHANGES IN REVENUES AND COSTS
Natural Gas Revenues and Cost of Natural Gas
SoCalGas’ average cost of natural gas per thousand cubic feet was $3.92 in 2025 and $3.28 in 2024. The average cost of natural gas sold at SoCalGas is impacted by market prices, as well as transportation and other charges.
In 2025 compared to 2024, SoCalGas’ natural gas revenues increased by $82 million (1%) to $6.3 billion primarily due to:
▪ $162 million higher CPUC-authorized base revenues, net of $34 million lower authorized cost of capital
▪ $139 million increase in cost of natural gas sold, which we discuss below
▪ $59 million higher revenues from incremental and balanced capital projects offset by lower authorized cost of capital
Offset by:
▪ $129 million lower regulatory revenues primarily from the release of a regulatory liability in 2024 for gas repairs tax benefits as a result of the 2024 GRC FD
▪ $54 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)
▪ $44 million lower regulatory revenues associated with refundable programs, which are fully offset in O&M
▪ $29 million lower revenues in 2025 from disallowed regulatory recovery of COVID-19 costs
▪ $9 million lower regulatory award approved by the CPUC
In 2025 compared to 2024, SoCalGas’ cost of natural gas increased by $139 million (14%) to $1.1 billion due to:
▪ $181 million higher average natural gas prices
Offset by:
▪ $42 million lower volumes driven by weather
Operation and Maintenance
In 2025 compared to 2024, SoCalGas’ O&M decreased by $102 million (4%) to $2.7 billion due to:
▪ $44 million lower expenses associated with refundable programs, which costs are recovered in revenue
▪ $38 million lower non-refundable operating costs
▪ $20 million impairment in 2024 from disallowed capital costs in the 2024 GRC FD
Other (Expense) Income, Net
In 2025 compared to 2024, SoCalGas’ other expense, net, was $6 million compared to other income, net, of $25 million primarily due to:
▪ $13 million higher non-service components of net periodic benefit cost
▪ $11 million lower net interest income on regulatory balancing accounts
▪ $7 million reduction in regulatory interest in 2025 from disallowed regulatory recovery of COVID-19 costs
Income Taxes
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Years ended December 31,
SoCalGas:
Income tax (benefit) expense
Income before income taxes
Effective income tax rate
In 2025 compared to 2024, SoCalGas had an income tax benefit in 2025 compared to income tax expense in 2024 primarily due to:
▪ lower pretax income
▪ higher income tax benefit from flow-through items, including $47 million income tax benefit in 2025 from the election to accelerate self-developed software deductions, which we discuss in Note 8 of the Notes to Consolidated Financial Statements
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CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
Sempra
Capital Recycling Program
We regularly review our portfolio of assets with a view toward allocating capital to the businesses we believe can further enhance shareholder value. 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. In December 2025, we entered into an agreement to sell Ecogas for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. We expect to complete the sales in the second or third quarter of 2026, subject to closing conditions. We discuss these sales further in Note 6 of the Notes to Consolidated Financial Statements and below in “Sempra Infrastructure.”
Liquidity
We expect to meet our cash requirements primarily through:
▪ cash flows from operations
▪ unrestricted cash and cash equivalents
▪ borrowings under or supported by our credit facilities
▪ other incurrences of debt which may include issuing debt securities and obtaining term loans
▪ selling assets or equity interests in our subsidiaries or development projects, including the planned sale of a portion of our equity interest in SI Partners
▪ issuing equity securities under our ATM program or other offerings
▪ funding from NCI owners or CRNCI owners
We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:
▪ finance capital expenditures
▪ repay debt
▪ fund dividends
▪ fund contractual and other obligations and otherwise meet liquidity requirements
▪ fund capital contributions
▪ fund new business or asset acquisitions
Sempra, SDG&E and SoCalGas currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow or otherwise raise money at market rates from commercial banks, under existing revolving credit facilities, through public offerings of debt or equity securities (including under our ATM program or other offerings), or through private placements of debt supported by our revolving credit facilities in the case of commercial paper. However, our ability to access these markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if economic conditions worsen or disruptions to or volatility in these markets increase. In addition, our financing activities, actions by credit rating agencies and prevailing interest rates, as well as many other factors, could negatively affect the availability and cost of both short-term and long-term debt and equity financing. Also, cash flows from operations may be impacted by the timing and outcomes of regulatory proceedings, commencement and completion of, and potential cost overruns for, large projects and other material events. If cash flows from operations were to be significantly reduced or we were unable to borrow or obtain other financing under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety or reliability) and investments in new businesses. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our goal to maintain our investment-grade credit ratings.
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Redemption of Series C Preferred Stock
As we discuss in Note 13 of the Notes to Consolidated Financial Statements, in September 2025, we provided notice of the redemption of all 900,000 issued and outstanding shares of our series C preferred stock for a redemption price in cash of $1,000 per share. On October 15, 2025, we effected and paid $900 million for the redemption using proceeds received from our August 2025 issuance of junior subordinated notes and short-term debt, which we discuss below and in Note 7 of the Notes to Consolidated Financial Statements.
ATM Program and Forward Sales Agreements
In November 2024, we established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion through agents acting as our sales agents or as forward sellers or directly to the agents as principals. The shares may be offered and sold in amounts and at times to be determined by us from time to time.
Since establishing the ATM program, an aggregate of 4,996,591 shares have been sold under the forward sale agreements described below with an average initial forward price of $83.175 per share. Such average initial forward price is weighted to take into account the number of shares sold under each forward sale agreement.
In the fourth quarter of 2024, we entered into a forward sale agreement under the ATM program for the sale of 2,909,274 shares of Sempra common stock that remain subject to future settlement. At the initial forward price of $92.1546 per share, the net proceeds from this forward sale agreement if we elect full physical settlement would be approximately $268 million. At December 31, 2025, a total of 2,909,274 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than June 30, 2026.
In the first quarter of 2025, we entered into a forward sale agreement under the ATM program for the sale of 2,087,317 shares of Sempra common stock that remain subject to future settlement. At the initial forward price of $70.6593 per share, the net proceeds from this forward sale agreement if we elect full physical settlement would be approximately $147 million. At December 31, 2025, a total of 2,087,317 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than March 31, 2027.
We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreements. Although we may settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements.
At December 31, 2025, approximately $2.6 billion of common stock remained available for sale under the ATM program.
We further discuss these activities, including the intended use of proceeds and effect on diluted EPS, in Note 13 of the Notes to Consolidated Financial Statements.
Available Funds
Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each have a committed line of credit expiring in 2030. Sempra Infrastructure has five committed lines of credit expiring on various dates from 2026 through 2030 and an uncommitted line of credit expiring in 2026, which are included in the held for sale disposal group but remain legally accessible and are sources of available credit to Sempra Infrastructure until the planned sale of a portion of our equity interest in SI Partners closes.
AVAILABLE FUNDS AT DECEMBER 31, 2025
(Dollars in millions)
Sempra
SDG&E
SoCalGas
Unrestricted cash and cash equivalents (1)
Available unused credit (2)
(1) Sempra includes $81 held in foreign jurisdictions, which is included in the $112 that is classified as Assets Held for Sale in the Sempra Consolidated Balance Sheet. We discuss repatriation in Note 8 of the Notes to Consolidated Financial Statements.
(2) Available unused credit is the total available on committed and uncommitted lines of credit that we discuss in Note 7 of the Notes to Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding and any letters of credit outstanding as a reduction to the available unused credit.
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Short-Term Borrowings
We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures or acquisitions. SDG&E and SoCalGas use short-term debt primarily to meet working capital needs or to help fund event-specific costs. Commercial paper, term loans and lines of credit were our primary sources of short-term debt funding in 2025.
We discuss our short-term debt activities in Note 7 of the Notes to Consolidated Financial Statements and below in “Sources and Uses of Cash.”
The following table shows selected statistics for our commercial paper borrowings.
COMMERCIAL PAPER STATISTICS
(Dollars in millions)
Sempra
SDG&E
SoCalGas
December 31,
Amount outstanding at period end
Weighted-average interest rate at period end
Daily weighted-average outstanding balance
Daily weighted-average yield
Maximum daily amount outstanding
Long-Term Debt Activities
Significant issuances of and payments on long-term debt in 2025 included the following:
Sempra Infrastructure loan at variable rates (4.03% after floating-to-fixed rate swap effective 2019) payable June 15, 2022 through November 19, 2034
At December 31, 2025, Sempra expects to make interest payments on long-term debt totaling $27.0 billion, of which $1.4 billion is expected to be paid in 2026 and $25.6 billion is expected to be paid in subsequent years through 2079. These amounts exclude the disposal group that is classified as held for sale, which has expected interest payments on long-term debt totaling $3.3 billion, of which $400 million is expected to be paid in 2026 and $2.9 billion is expected to be paid in subsequent years through 2051. At December 31, 2025, SDG&E expects to make interest payments on long-term debt totaling $6.7 billion, of which $400 million is expected to be paid in 2026 and $6.3 billion is expected to be paid in subsequent years through 2054. At December 31, 2025, SoCalGas expects to make interest payments on long-term debt totaling $6.5 billion, of which $400 million is expected to be paid in 2026 and $6.1 billion is expected to be paid in subsequent years through 2055. We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. We calculate expected interest payments for variable-rate obligations based on forecasted rates in effect at December 31, 2025.
We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, and maturities in Note 7 of the Notes to Consolidated Financial Statements.
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Credit Ratings
The credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in 2025.
ISSUER CREDIT RATINGS AT DECEMBER 31, 2025
Sempra
SDG&E
SoCalGas
Moody’s
Baa2 with a negative outlook
A3 with a stable outlook
A2 with a stable outlook (1)
BBB+ with a negative outlook
BBB+ with a stable outlook
A- with a stable outlook
Fitch
BBB+ with a stable outlook
BBB+ with a stable outlook
A with a stable outlook
(1) Reflects the senior unsecured rating, as no issuer credit rating is available.
A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks (which occurred in January 2025 with respect to S&P’s rating outlook for Sempra and credit rating for SoCalGas and in March 2025 with respect to Moody’s rating outlook for Sempra) may, depending on the severity, result in the imposition of new financial or other burdensome covenants or a requirement for collateral to be posted in the case of certain financing arrangements and may materially and adversely affect the market prices of their equity and debt securities, the rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra, SDG&E, SoCalGas and Sempra’s other subsidiaries to issue debt or equity securities, to borrow under credit facilities and to raise certain other types of financing. We provide additional information about our credit ratings at Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors.”
Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A and A at Moody’s, S&P and Fitch, respectively, at December 31, 2025.
Sempra, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit that may be impacted by each borrower’s credit rating. For example, assuming a one-notch downgrade:
▪ If Sempra were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 bps. The commitment fee on available unused credit would also increase 5 bps.
▪ If SDG&E were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 5 bps.
▪ If SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 2.5 bps.
Sempra’s, SDG&E’s and SoCalGas’ credit ratings also may affect their respective credit limits related to derivative instruments, as we discuss in Note 10 of the Notes to Consolidated Financial Statements.
Postretirement Benefits
Sempra, SDG&E and SoCalGas have significant investments in several trusts to provide for future payments of pensions and PBOP. The trusts’ ability to make ongoing required benefit payments has not been materially adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, changes in asset values or other factors in future periods (such as changes to discount rates, assumed rates of return, mortality tables and regulations) may impact funding requirements for pension and PBOP plans. Additionally, contributions to our plans are based on our funding policy, which generally limits payments from exceeding plan assets of 110% of the projected benefit obligation, which are subject to maximum income tax deduction limitations. Sempra, SDG&E and SoCalGas expect to contribute $240 million, $56 million and $152 million, respectively, to pension and PBOP plans in 2026 and $1.2 billion, $494 million and $590 million, respectively, in the nine years thereafter. Sempra’s amounts exclude $2 million in 2026 and $29 million in the nine years thereafter related to the disposal group that is classified as held for sale. At SDG&E and SoCalGas, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and our expected contributions to those plans in Note 9 of the Notes to Consolidated Financial Statements.
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Sempra California
SDG&E’s and SoCalGas’ operations have historically provided relatively stable earnings and liquidity. Their future performance and liquidity will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by legislatures, litigation and the changing energy marketplace, as well as other matters described in this report. SDG&E and SoCalGas expect that the available unused funds from their credit facilities described above, which also supports their commercial paper programs, cash flows from operations, and other incurrences of debt including issuing debt securities and obtaining term loans will continue to be adequate to fund their respective current operations and planned capital expenditures. SDG&E and SoCalGas manage their capital structures and pay dividends as approved by their respective boards of directors.
SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to Accounts Receivable – Trade that are probable of recovery in regulatory accounts. Although SDG&E and SoCalGas have regulatory mechanisms to recover credit losses, any delay in payments by customers impacts the timing of their respective cash flows.
As we discuss in Note 4 of the Notes to Consolidated Financial Statements, changes in regulatory balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over and undercollected status, may have a significant impact on cash flows. These changes generally represent the difference between when costs are incurred and when they are ultimately recovered or refunded in rates through billings to customers.
CPUC GRC
As we discuss in Note 4 of the Notes to Consolidated Financial Statements, in December 2024, the CPUC approved an FD in the 2024 GRC for SDG&E and SoCalGas that authorizes SDG&E’s and SoCalGas’ revenue requirements for 2024 and attrition year adjustments for 2025 through 2027, inclusively. The incremental revenue requirements associated with the period from January 1, 2024 through January 31, 2025 are being recovered in rates over an 18-month period that began on February 1, 2025.
Petition for Modification. In December 2025, SDG&E and SoCalGas filed a petition for modification of the 2024 GRC, seeking to modify the post-test year mechanism for capital related costs. The petition for modification seeks increases of $55 million, $87 million and $79 million to the approved revenue requirements for SDG&E for 2025, 2026 and 2027, respectively, and increases of $86 million, $122 million and $109 million to the approved revenue requirements for SoCalGas for 2025, 2026 and 2027, respectively. There is no established timeline for the CPUC to act on this filing.
Existing and Anticipated Requests for Recovery of Specified Safety, Maintenance and Reliability Investments. The GRC provides SDG&E and SoCalGas with numerous mechanisms to seek cost recovery of specified projects and programs. We expect that the requests for cost recovery of these projects and programs, which remain subject to CPUC approval, may result in additional amounts of authorized revenue requirement. These projects and programs include (i) the Track 2 and Track 3 requests that we describe below, (ii) the ability to file advice letters to implement the revenue requirements associated with the costs of SDG&E’s Moreno compressor station project and SoCalGas’ Honor Rancho compressor station and customer information system replacement projects, which projects were all approved by the CPUC subject to applicable cost caps, and (iii) the opportunity to file separate applications for cost recovery of mobile home park and gas integrity management programs at both SDG&E and SoCalGas, advanced metering infrastructure replacements at SDG&E, and other projects and programs.
2024 GRC Track 2. In October 2023, SDG&E submitted a separate request to the CPUC in its 2024 GRC, known as a Track 2 request. This request seeks review and recovery of $1,472 million of WMP costs incurred from 2019 through 2022 that were incremental to amounts authorized in the 2019 GRC and not otherwise addressed in the 2024 GRC FD. In January 2026, the CPUC issued an FD in SDG&E’s Track 2 request that approves recovery of $1,023 million of these requested costs, including $78 million of O&M costs and $945 million of capital costs. The Track 2 FD allows SDG&E to seek recovery in Track 3 of this proceeding of the drone inspection and repair program costs that were disallowed in the Track 2 FD.
The Track 2 request also addresses SDG&E’s requested revenue requirement for the period from 2019 through 2027 for ongoing capital-related costs for capital assets placed into service from 2019 through 2022. The FD authorizes a total Track 2 revenue requirement of $707 million for 2019 through 2027, which is $441 million lower than SDG&E’s requested revenue requirement of $1,148 million. In February 2024, the CPUC authorized an interim cost recovery mechanism that permitted SDG&E to collect in rates $194 million and $96 million of this revenue requirement in 2024 and 2025, respectively. The FD authorizes SDG&E to collect the remaining $417 million from 2026 through 2028.
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2024 GRC Track 3. In April 2025, SDG&E and SoCalGas each submitted additional requests to the CPUC in the 2024 GRC, known as Track 3 requests. SDG&E submitted a request seeking review and recovery of $417 million of its WMP costs incurred in 2023 that were in addition to the amounts authorized in the 2019 GRC and not addressed in the 2024 GRC. SDG&E expects to provide supplemental testimony in its Track 3 request for drone inspection and repair program costs that were disallowed in its Track 2 request. SDG&E expects to receive a PD for its Track 3 request related to its WMP costs in the second half of 2026. Additionally, SDG&E and SoCalGas submitted a combined request seeking review and recovery of $240 million of PSEP costs incurred from 2014 through 2019 and $499 million of PSEP costs incurred from 2015 through 2020. SDG&E and SoCalGas expect to receive a PD for their Track 3 requests related to their PSEP costs in the first half of 2026.
Revenue requirements associated with the Track 3 requests have been recorded in regulatory accounts and disallowances resulting from Track 3 would be recorded as an expense on the Sempra, SDG&E and SoCalGas Consolidated Statements of Operations. SDG&E and SoCalGas are authorized interim rate recovery of up to 50% of the recorded PSEP regulatory account balance at the end of each year. Such interim rate recovery is subject to refund, contingent on the reasonableness review decision for their Track 3 requests.
Accounting Impact of Regulatory Disallowances. In connection with the Track 2 FD, in the fourth quarter of 2025, SDG&E recorded a charge of $651 million ($464 million after tax) in Regulatory Disallowances on the SDG&E and Sempra Consolidated Statements of Operations, of which $605 million ($432 million after tax) relates to 2019 through 2024, $41 million ($28 million after tax) relates to the first nine months of 2025, and $5 million ($4 million after tax) relates to the fourth quarter of 2025.
CPUC Cost of Capital
In December 2025, the CPUC approved an FD in SDG&E’s and SoCalGas’ applications seeking to update their cost of capital, effective January 1, 2026 through December 31, 2028, subject to the CCM. The FD maintains the current authorized capital structure with an equity layer of 52% and authorizes an ROE of 9.93% and 9.78% for SDG&E and SoCalGas, respectively. We further discuss the cost of capital and CCM in Note 4 of the Notes to Consolidated Financial Statements.
SDG&E
Golden Pacific Powerlink
The California ISO’s 2022-2023 Transmission Plan identified the need for 45 transmission projects throughout the state to improve resiliency and modernize the region’s energy grid. As part of the Transmission Plan, SDG&E expects to construct, own and operate a 500-kV transmission line, referred to as the Golden Pacific Powerlink, that is slated to run through SDG&E’s service territory between the existing Imperial Valley Substation and the border of San Diego and Orange Counties.
SDG&E anticipates filing for a certificate of public convenience and necessity from the CPUC in the second half of 2026 that will include proposed routing and design elements. The Transmission Plan estimates construction on the Golden Pacific Powerlink transmission line to begin in 2029, with a target in-service date of 2034, subject to obtaining necessary state and federal agency approvals and permits.
Wildfire Fund and Continuation Account
The 2019 Wildfire Legislation established the Wildfire Fund and the 2025 Wildfire Legislation established the Continuation Account (collectively, the Wildfire Legislation), which offer liquidity to reimburse wildfire-related claims incurred by participating California electric IOUs in excess of $1 billion, subject to the coverage of each fund. The Wildfire Fund and the Continuation Account, if it becomes operative, could be materially reduced, exhausted, or terminated due to claims by SDG&E or other participating IOUs related to fires caused by utility conduct or operations, or SDG&E could fail to maintain a valid annual safety certification from the OEIS or meet other requirements, any of which could result in SDG&E losing eligibility for the Wildfire Legislation’s liability cap and the other protections afforded by these funds. As a result, a fire resulting from the conduct or operations of any participating California electric IOU could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects, with potentially material additional exposure if SDG&E’s conduct or operations is determined to be a cause of a fire and SDG&E is found to have acted imprudently.
2019 Wildfire Legislation . We describe the 2019 Wildfire Legislation and SDG&E’s commitment to make annual shareholder contributions to the Wildfire Fund through 2028 in Note 1 of the Notes to Consolidated Financial Statements.
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SDG&E is exposed to the risk that the participating California electric IOUs may incur third-party wildfire costs for which they will seek recovery from the Wildfire Fund with respect to wildfires that have occurred since enactment of the 2019 Wildfire Legislation in July 2019. In such a situation, SDG&E may recognize a reduction of its Wildfire Fund asset and record accelerated amortization against earnings when available coverage is reduced due to recoverable claims from any of the participating IOUs. The carrying value of SDG&E’s Wildfire Fund asset totaled $260 million at December 31, 2025.
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.
2025 Wildfire Legislation. We describe the 2025 Wildfire Legislation that was signed into law in September 2025 in Note 1 of the Notes to Consolidated Financial Statements. The 2025 Wildfire Legislation established, among other things, the Continuation Account, a new state-administered account with up to $18.0 billion of additional liquidity to reimburse catastrophic wildfire-related claims incurred by participating California electric IOUs, including SDG&E, if (i) the Wildfire Fund is anticipated to be depleted or (ii) a catastrophic fire igniting after September 19, 2025 and before December 31, 2028 results in claims expected to exceed $1 billion. The funds in the account would only be available for claims arising from wildfires that ignited on or after September 19, 2025. The 2025 Wildfire Legislation preserves key elements of the 2019 Wildfire Legislation, including standards and requirements for recovery of costs related to catastrophic wildfire-related claims, a liability cap in the event of a finding of imprudence by the CPUC, and continued access to wildfire claims liquidity through the new Continuation Account. All of California’s large electric IOUs, including SDG&E, have elected to participate in the Continuation Account.
If the Continuation Account becomes operative, it would be funded with a combination of $9.0 billion from ratepayer contributions and $9.0 billion from electric IOU shareholder contributions. Electric IOU shareholder contributions totaling $5.1 billion would be obtained through fixed annual contributions of $300 million from 2029 through 2045, plus an additional $3.9 billion in contingent shareholder contributions payable in annual installments of $780 million. SDG&E’s proportionate share of the aggregate shareholder contribution amount through 2045 is expected to be $387 million, comprising (i) $219.3 million of fixed contributions of $12.9 million annually for 17 years, and (ii) $167.7 million of contingent contributions of $33.5 million annually for five years.
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.
FERC Rate Matters
SDG&E files separately with the FERC for its authorized transmission revenue requirement and ROE on FERC-regulated electric transmission operations and assets.
TO5 Settlement. SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision had been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019.
TO6 Filing. In October 2024, SDG&E submitted its TO6 filing to the FERC and requested it to be effective January 1, 2025. SDG&E’s TO6 filing proposed, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing, subject to refund; suspended the effective date to June 1, 2025; established hearing and settlement judge procedures; and disallowed the inclusion of the California ISO adder, the last of which SDG&E has appealed. In February 2026, the settlement judge in the TO6 proceeding reported to the FERC that the participants had reached an agreement in principle on all issues in the proceeding. The parties will draft an offer of settlement to be filed with the FERC for approval.
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SONGS Decommissioning
SDG&E has significant investments in the SONGS NDT to provide for future payments of nuclear decommissioning. The NDT’s ability to make ongoing required payments has not been materially or adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, asset values could be materially and adversely affected by future activity in the equity and fixed income markets, and changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions to the estimated total cost associated with retiring the assets. Funding requirements are generally recoverable in rates. We discuss SDG&E’s NDT and its expected SONGS decommissioning payments in Note 15 of the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
SDG&E has entered into PPAs and tolling agreements that are variable interests in unconsolidated entities. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.
SoCalGas
Catastrophic Events Cost Recovery
In July 2025, the CPUC issued an FD that authorizes partial recovery of costs recorded in SoCalGas’ Catastrophic Event Memorandum Account. The FD authorizes the recovery of $19 million out of the requested $55 million, denying recovery of COVID-19 costs included in the Catastrophic Event Memorandum Account. In the year ended December 31, 2025, SoCalGas recorded a write-off of $36 million ($25 million after tax) in disallowed costs, comprising a $29 million reduction in Utilities: Natural Gas Revenues and a $7 million reduction in regulatory interest in Other (Expense) Income, Net, on Sempra’s and SoCalGas’ Consolidated Statements of Operations. The CPUC denied SoCalGas’ request for a rehearing of the FD.
LA Fires
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. We cannot estimate the timing, costs, other impacts or ultimate outcome of these matters, which are inherently uncertain and subject to a number of risks that we discuss in “Part I – Item 1A. Risk Factors.”
SoCalGas has mechanisms available for potential recovery of costs associated with declared disasters and related litigation, including through insurance, third parties and customer rates. Failure by SoCalGas to timely recover all or a substantial portion of its costs related to the LA Fires or any conclusion that such recovery is no longer probable could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Labor Relations
Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council. The collective bargaining agreement for these employees covering wages, hours, working conditions, and medical and other benefit plans was due to expire on September 30, 2024, but was extended by mutual agreement while SoCalGas and the unions continued negotiations. A new collective bargaining agreement was ratified on March 31, 2025, effective July 1, 2025, and is scheduled to expire on September 30, 2028.
Sempra Texas Utilities
Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the event that Oncor is unable to meet its capital requirements, access sufficient capital, or raise capital on favorable terms to finance its ongoing needs, we may elect to make additional capital contributions to Oncor (as our commitments to the PUCT prohibit us from making loans to Oncor), which could be substantial and reduce the cash available to us for other purposes, increase our indebtedness and ultimately materially adversely affect our results of operations, financial condition, cash flows and/or prospects. Oncor’s ability to make distributions may be limited by factors such as its credit ratings, regulatory capital requirements, increases in its capital plan, debt-to-equity ratio approved by the PUCT and other restrictions and considerations. In addition, Oncor will not make distributions if a majority of Oncor’s independent directors or any minority member director determines it is in the best interests of Oncor to retain such amounts to meet expected future requirements.
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Oncor
2025 Comprehensive Base Rate Review. In June 2025, Oncor filed a request for a comprehensive base rate review with the PUCT and the 210 cities in its service territory that have retained original jurisdiction over rates. The base rate review test year is based on calendar year 2024 results with certain adjustments. The base rate review includes a request for an average increase over test year adjusted annualized revenue of approximately 13%, which would result in an aggregate annualized revenue increase of approximately $834 million over current adjusted rates. The base rate review also requests a revised regulatory capital structure ratio of 55% debt to 45% equity, an authorized ROE of 10.55%, and a 4.94% authorized cost of debt. Oncor’s current authorized regulatory capital structure ratio is 57.5% debt to 42.5% equity, a 9.7% authorized ROE and 4.39% authorized cost of debt.
On January 29, 2026, Oncor filed a stipulation in the comprehensive base rate review proceeding requesting PUCT approval of an unopposed, comprehensive settlement among the parties to the proceeding. Among other things, the stipulation provides for an increase of approximately 8.8% over the adjusted annualized present revenues provided in the rate application. If approved as requested, Oncor estimates the terms of the stipulation would result in an aggregate annualized increase over those revenues of approximately $560 million. Moreover, the stipulation also provides for a revised regulatory capital structure ratio of 56.5% debt to 43.5% equity, an authorized ROE of 9.75%, and an authorized cost of debt of 4.94%.
The PUCT may choose to adopt, modify, or reject the stipulation and the proposed order included in the stipulation. Oncor expects the PUCT to issue a final order in the proceeding in the first half of 2026. New billing rates would be implemented after that final order. If the proposed new rates in the stipulation are approved as requested, Oncor will surcharge the difference between those new rates and its current rates back to January 1, 2026, pursuant to a previously approved settlement regarding interim rates.
Unified Tracker Mechanism. In June 2025, Texas House Bill 5247 was signed into law and became effective. The bill established the UTM, which allows qualifying electric utilities to apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments.
Oncor expects to make its first comprehensive UTM filing on or after March 16, 2026 with a view toward recovering the costs associated with eligible transmission and distribution investments that were placed into service after December 31, 2024 through December 31, 2025 and that are not currently reflected in rates. Since the June 2025 effective date of the bill, Oncor has recognized revenues and corresponding regulatory assets for recoverable costs related to UTM-eligible transmission and distribution capital investments that were placed into service from January 1, 2025 through December 31, 2025, including depreciation expense, carrying costs on unrecovered balances and related taxes. Oncor expects to continue recognizing revenues and corresponding regulatory assets as UTM-eligible transmission and distribution capital investments are placed into service.
Sharyland Utilities
In November 2025, the PUCT approved Sharyland Utilities’ 2025 rate case, setting its total revenue requirement at $53 million, with a capital structure ratio of 59% debt to 41% equity, an ROE of 9.60%, and a long-term cost of debt of 4.52%.
Off-Balance Sheet Arrangement
Our investment in Oncor Holdings is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.
Sempra Infrastructure
Sempra Infrastructure expects to fund capital expenditures, investments and operations in part with available funds, including existing credit facilities, and cash flows from operations from the Sempra Infrastructure businesses. We expect Sempra Infrastructure will require additional funding for the development and expansion of its portfolio of projects, which may be financed through a combination of funding from the parent and NCI owners, bank financing, issuances of debt, project financing, partnering in JVs and asset sales.
In 2025, 2024 and 2023, Sempra Infrastructure distributed $609 million, $297 million and $730 million, respectively, to its NCI owners, and NCI owners contributed $327 million, $1,235 million and $1,770 million, respectively, to Sempra Infrastructure.
Sempra Infrastructure is in various stages of development or construction of natural gas liquefaction projects, pipeline and terminal projects, and renewable power generation and sequestration projects, which we describe below. The successful development and/or construction of these projects is subject to numerous risks and uncertainties.
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With respect to projects in development, these risks and uncertainties include a variety of factors as applicable depending on the project and many of which are outside our control, including any failure to:
▪ secure binding customer commitments
▪ identify suitable project and equity partners
▪ obtain sufficient financing
▪ reach agreement with project partners or other applicable parties to proceed
▪ obtain, modify, and/or maintain permits and regulatory approvals, including LNG export applications to non-FTA countries and any applicable approvals in Mexico
▪ negotiate, complete and maintain suitable commercial agreements, which may include EPC, tolling, equity acquisition, governance, LNG sales, gas supply and transportation contracts
▪ reach a positive FID
With respect to projects under construction, these risks and uncertainties include, in addition to the risks described above as applicable to each project, construction delays, unforeseen design flaws, cost overruns, stakeholder relations issues and other construction-related issues.
An unfavorable outcome with respect to any of these factors could have a material adverse effect on (i) the development and construction of the applicable project, including a potential impairment of all or a substantial portion of the capital costs invested in the project to date, which could be material, and (ii) for any project that has reached a positive FID, Sempra’s results of operations, financial condition, cash flows and/or prospects. For a further discussion of these risks, see “Part I – Item 1A. Risk Factors.”
The descriptions below discuss several HOAs, MOUs and other non-binding development agreements with respect to Sempra Infrastructure’s various development projects. These arrangements do not commit any party to enter into definitive agreements or otherwise participate in the applicable project, and the ultimate participation by the parties remains subject to negotiation and finalization of definitive agreements, among other factors. The descriptions below also discuss certain financing arrangements for several of Sempra Infrastructure’s projects in development and under construction; we discuss these and other financing arrangements related to these projects in more detail in Note 7 of the Notes to Consolidated Financial Statements.
With respect to each project described below that has reached a positive FID, long-term definitive offtake agreements have been secured with third parties for the full initial offtake or generation capacity of the applicable project, other than an SPA with SI Partners for a portion of the offtake from the PA LNG Phase 2 project, which SI Partners intends to resell to third parties under offtake arrangements it plans to establish from time to time. We describe these SPAs in “Part I – Item 1. Business.”
SI Partners
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. As a result of satisfying all applicable criteria in September 2025, we classified SI Partners’ assets and liabilities as held for sale and ceased depreciation and amortization.
The agreement provides that, subject to adjustments described in Note 6 of the Notes to Consolidated Financial Statements, the purchase price will be paid to Sempra as follows:
▪ $4.65 billion in cash at closing;
▪ $4.14 billion plus interest compounded quarterly at 7.5% per annum (totaling $4.72 billion with principal and accrued interest unless paid early) due December 31, 2027 under instruments backed by equity commitment letters; and
▪ $1.2 billion plus interest compounded quarterly at 8.5% per annum before January 1, 2031 and 10.0% per annum thereafter (totaling $2.29 billion with principal and accrued interest unless paid early) due seven years and 91 days after closing under promissory notes.
Subject to closing, the KKR Partners will own 65% of SI Partners, Sempra will retain a 25% interest and ADIA will retain a 10% interest. We will then deconsolidate SI Partners and account for our 25% interest in SI Partners under the equity method within the existing Sempra Infrastructure segment. For a description of Sempra’s December 31, 2025 and projected post-sale ownership interest in certain Sempra Infrastructure facilities and projects, see “Part I – Item 1. Business.”
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The rights and obligations of the partners of SI Partners are governed by a limited partnership agreement, which will be amended and restated at closing. This limited partnership agreement contains certain provisions on project funding and distributions that could impact Sempra’s results of operations and cash flows. For instance, the existing limited partnership agreement provides for certain priority distributions to one or more of the minority partners if certain cash flow or rate of return performance levels are not achieved or a specified project that reaches a positive FID does not meet certain other conditions by certain dates. In addition, the post-closing limited partnership agreement provides that Sempra will continue to have substantially similar funding obligations as it has before the sale for cost overruns in the ECA LNG Phase 1 project and the PA LNG Phase 1 project. For more information about the terms of the limited partnership agreement, see “Part I – Item 1. Business” and Note 6 of the Notes to Consolidated Financial Statements.
LNG
Cameron LNG Phase 2 Project. Cameron LNG JV is developing a proposed expansion project that would add one electric drive liquefaction train with an expected maximum production capacity of approximately 6.75 Mtpa and would increase the production capacity of the existing three trains at the Cameron LNG Phase 1 facility by up to approximately 1 Mtpa through debottlenecking activities. The Cameron LNG JV site can accommodate additional trains beyond the proposed Cameron LNG Phase 2 project.
Cameron LNG JV has received major permits and FTA and non-FTA approvals associated with the potential expansion. In November 2025, we received approval from the FERC to extend the deadline for construction authorization until March 2033. The non-FTA approval for the proposed Cameron LNG Phase 2 project includes, among other things, a May 2026 deadline to commence commercial exports. In October 2025, we filed a request with the DOE to extend that deadline to the first quarter of 2033.
SI Partners and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, have entered into a non-binding HOA for the potential development of the Cameron LNG Phase 2 project. The non-binding HOA provides a commercial framework for the proposed project, including the contemplated allocation to SI Partners of 50.2% of the fourth train production capacity and 25% of the debottlenecking capacity from the project under tolling agreements. The non-binding HOA contemplates the remaining capacity to be allocated equally to the existing Cameron LNG Phase 1 facility customers.
Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, and Cameron LNG JV have an electricity service agreement (and related ancillary agreements) for the supply to Cameron LNG JV of up to 950 MW of power from renewable sources in Louisiana.
Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the members, including with respect to the equity investment obligation of each member. Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is also subject to certain restrictions and conditions under the JV project financing agreements, including, among others, scope restrictions on expansion of the project unless appropriate prior consent is obtained from the existing project lenders. An FID remains subject to, among other things, securing these consents of the members and project lenders, satisfactory conclusion on certain ongoing engineering processes and selection of an EPC contractor, negotiation and finalization of definitive offtake agreements and completion of all related financing and permitting activities.
ECA LNG Phase 1 Project. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of SI Partners’ existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility.
We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the ECA LNG Phase 1 project. In September 2025, we submitted a filing with the DOE to extend the construction deadline associated with our non-FTA permits until the end of summer 2026.
We have an EPC contract with TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of Technip Energies N.V., to construct the ECA LNG Phase 1 project. We estimate the total price of the EPC contract to be approximately $1.6 billion, with capital expenditures of approximately $2.5 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. The ECA LNG Phase 1 project achieved mechanical completion in December 2025, and we expect the project to produce LNG cargoes for sale in the spring of 2026 and sales under the long-term SPAs to begin shortly after substantial completion when the facility commences commercial operations, which is targeted in the summer of 2026. Reaching substantial completion under the EPC contract is subject to various milestones, including achieving certain performance tests and functionality.
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ECA LNG Phase 1’s customers have a termination right under their SPAs if the ECA LNG Phase 1 project does not commence commercial operations under the SPAs by February 24, 2026, subject to certain additional conditions. As of February 26, 2026, no customers have given notice of their intent to terminate the SPAs.
ECA LNG Phase 1 has a loan agreement with a borrowing capacity of $1.5 billion that matures in December 2027. At December 31, 2025 and 2024, $1.3 billion and $1.1 billion, respectively, of borrowings were outstanding under the loan agreement. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project.
With respect to the ECA LNG Phase 1 project and the ECA LNG Phase 2 project that we discuss below, recent and proposed changes to the Mexican Constitution and certain laws in Mexico and an unfavorable resolution of a land dispute and permit challenges, in each case that we discuss in Note 16 of the Notes to Consolidated Financial Statements, could have a material adverse effect on the development and construction of these projects.
ECA LNG Phase 2 Project. SI Partners is developing a second, large-scale natural gas liquefaction project at the site of its existing ECA Regas Facility in Baja California, Mexico. We expect the proposed ECA LNG Phase 2 project to be comprised of multiple trains and one additional LNG storage tank and produce approximately 12 Mtpa of export capacity. We expect that future construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which has a firm storage and nitrogen injection service agreement that expires in May 2028, to the extent this agreement has not expired or has not been earlier terminated at the time of such construction.
We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the proposed ECA LNG Phase 2 project. In February 2026, the DOE extended the construction deadline associated with the project to December 2029.
We have non-binding MOUs and/or HOAs that provide a framework for potential offtake of LNG from the proposed ECA LNG Phase 2 project and potential acquisition of equity interests in ECA LNG Phase 2.
PA LNG Phase 1 Project. SI Partners is constructing a natural gas liquefaction project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. The PA LNG Phase 1 project will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa.
SI Partners has received authorizations from the DOE that permit the export of LNG to be produced from the PA LNG Phase 1 project to all current and future FTA and non-FTA countries, and from the FERC for the siting, construction and operation of the PA LNG Phase 1 project.
We have an EPC contract with Bechtel to construct the PA LNG Phase 1 project, which has an estimated price of approximately $10.8 billion, with capital expenditures for the project of approximately $13 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. The first train of the Port Arthur LNG liquefaction project remains on schedule, and we continue to expect the first and second trains to commence commercial operations at or near the end of 2027 and in 2028, respectively.
Port Arthur LNG I has a seven-year term loan facility for an aggregate principal amount of approximately $6.8 billion and an initial working capital facility for up to $200 million, each of which matures in March 2030. At December 31, 2025, $3.2 billion of borrowings were outstanding and previous borrowings of $983 million have been repaid and cannot be reborrowed under the term loan facility agreement. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.
As we discuss in Note 13 of the Notes to Consolidated Financial Statements, SI Partners and ConocoPhillips have provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. As of December 31, 2025, an aggregate amount of $2.7 billion has been paid by SI Partners’ subsidiary in satisfaction of its commitment to fund its portion of the development budget of the PA LNG Phase 1 project.
As we discuss in Note 16 of the Notes to Consolidated Financial Statements, in April 2025, an incident occurred at the site of the PA LNG Phase 1 project that resulted in the deaths of three Bechtel employees and injuries to two Bechtel employees. OSHA opened inspections with respect to Bechtel and SI Partners but has released the site. OSHA’s inspection of SI Partners concluded without the issuance of citations to SI Partners. Bechtel is continuing construction of the PA LNG Phase 1 project. As of February 19, 2026, there are two pending lawsuits filed by 17 plaintiffs related to the incident. Bechtel is providing indemnity pursuant to the terms of Port Arthur LNG I’s EPC contract.
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PA LNG Phase 2 Project. Since reaching a positive FID in September 2025, SI Partners has commenced construction of a second phase of the Port Arthur LNG liquefaction project that we expect will be a similar size to the PA LNG Phase 1 project. The PA LNG Phase 2 project will consist of two liquefaction trains, one LNG storage tank, and associated facilities with a nameplate capacity of approximately 13 Mtpa.
SI Partners has received authorizations from the DOE that permit the export of LNG to be produced from the PA LNG Phase 2 project to all current and future FTA and non-FTA countries, and from the FERC for the siting, construction and operation of the PA LNG Phase 2 project.
In addition to the definitive SPAs that we discuss in “Part I – Item 1. Business,” SI Partners has a non-binding HOA with Aramco International Gas Holding Co B.V. contemplating a 20-year SPA for 5 Mtpa of LNG offtake and a 25% participation in project-level equity from the PA LNG Phase 2 project. The HOA will terminate in March 2026.
We have an EPC contract with Bechtel to construct the PA LNG Phase 2 project, which has an estimated price of approximately $9.2 billion, with capital expenditures of approximately $14 billion, including, among other items, project contingency and a $1.9 billion true-up payment to the PA LNG Phase 1 project to acquire a 50% interest in the shared common facilities. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the third and fourth trains of the Port Arthur LNG liquefaction project to commence commercial operations in 2030 and 2031, respectively.
As we discuss in Note 12 of the Notes to Consolidated Financial Statements, in September 2025, PA2 JVCo issued 49.9% of its equity interests to Blackstone for $3.4 billion in cash at closing and a commitment to fund an additional $3.6 billion of capital contributions on a pre-determined funding schedule whereby Blackstone’s capital contributions are scheduled prior to SI Partners’ capital contributions. SI Partners holds the remaining 50.1% of equity interests in PA2 JVCo and has committed to fund up to $7.8 billion to PA2 JVCo to support its share of the budgeted PA LNG Phase 2 project construction costs. SI Partners will continue to consolidate PA2 JVCo and direct the activities related to the construction and future operation and maintenance of the PA LNG Phase 2 project. Blackstone’s equity interest is subject to redemption and exit rights that are outside the control of SI Partners and Blackstone. As a result, we account for Blackstone’s NCI as being contingently redeemable, which is presented as CRNCI in Sempra’s Consolidated Balance Sheet.
To secure gas supply for the PA LNG Phase 2 project, SI Partners entered into a natural gas transportation agreement with a third-party pipeline developer. The transportation capacity commitment is subject to completion of pipeline construction by a third-party developer that is expected to occur by early 2029. SI Partners holds a contractual option to acquire the third party’s interest in the pipeline if certain construction milestones are not met, which acquisition would release SI Partners from the associated capacity commitment.
Vista Pacifico LNG Project. In partnership with the CFE, SI Partners was developing the Vista Pacifico LNG project, a mid-scale natural gas liquefaction export facility proposed to be located in the vicinity of the Port of Topolobampo in Sinaloa, Mexico. Due to a change in SI Partners’ and the CFE’s respective priorities, in December 2025, we agreed to terminate the existing development agreement.
Asset and Supply Optimization. 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.
Off-Balance Sheet Arrangements. Our investment in Cameron LNG JV is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.
In February 2025, SI Partners entered into a credit support agreement related to a customer’s secured borrowing for repayment of its past due account balance, which constitutes a guarantee, for the benefit of a third-party financial institution with a maximum exposure to loss of $85 million. The guarantee will terminate in May 2026. We discuss this guarantee in Note 16 of the Notes to Consolidated Financial Statements.
In June 2021, Sempra provided a promissory note, which constitutes a guarantee for the benefit of Cameron LNG JV with a maximum exposure to loss of $165 million. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt, scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra from the SDSRA. We discuss this guarantee in Note 16 of the Notes to Consolidated Financial Statements.
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In July 2020, Sempra entered into the Support Agreement, which contains a guarantee and represents a variable interest, for the benefit of CFIN with a maximum exposure to loss of $979 million. The guarantee will terminate upon full repayment of the guaranteed debt by 2039, including repayment following an event in which the guaranteed debt is put to Sempra. We discuss this guarantee in Notes 1 and 16 of the Notes to Consolidated Financial Statements.
Energy Networks
Ecogas. As we discuss in Note 6 of the Notes to Consolidated Financial Statements, in December 2025, we entered into an agreement to sell Ecogas to Gas Natural del Noroeste S.A. de C.V. for 9.0 billion Mexican pesos (approximately $500 million U.S. dollar-equivalent at December 31, 2025), subject to adjustments. In the first quarter of 2026, we entered into contingent foreign currency hedges that are designed to lock in the exchange rate associated with the anticipated after-tax net proceeds. We expect to complete the sale in the second or third quarter of 2026, subject to closing conditions. As a result of satisfying all applicable criteria in June 2025, we classified Ecogas’ assets and liabilities as held for sale and ceased depreciation and amortization.
Louisiana Storage. SI Partners is constructing Louisiana Storage, a 12.5-Bcf salt dome natural gas storage facility to support the PA LNG Phase 1 project. The construction includes an 11-mile pipeline that will connect to the Port Arthur Pipeline Louisiana Connector. We estimate the capital expenditures for the project will be approximately $400 million, including capitalized interest at the project level and project contingency. The actual amount of capital expenditures may differ substantially from our estimates. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project.
Port Arthur Pipeline Louisiana Connector. SI Partners is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana.
The FERC approved the siting, construction and operation of the Port Arthur Pipeline Louisiana Connector, which will be used to supply feed gas to the PA LNG Phase 1 project. Sempra Infrastructure received FERC approval to implement construction process enhancements and minor modifications to several discrete sections of the Port Arthur Pipeline Louisiana Connector. These modifications are intended to decrease environmental impacts, accommodate landowner routing requests and enhance construction procedures.
We estimate the capital expenditures for the project will be approximately $1 billion, including capitalized interest at the project level and project contingency. The actual amount of capital expenditures may differ substantially from our estimates. The Port Arthur Pipeline Louisiana Connector achieved mechanical completion in January 2026, and we expect it to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements.
Sonora Pipeline. Sempra Infrastructure’s Sonora natural gas pipeline consists of two pipeline segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017 because it was not able to be repaired due to legal challenges, which were resolved in March 2023, by some members of the Yaqui tribe.
In September 2019, Sempra Infrastructure and the CFE reached an agreement to modify the tariff structure and extend the term of the contract by 10 years. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is back in service.
In December 2025, Sempra Infrastructure and the CFE further amended their transportation services agreement to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE has agreed to reimburse Sempra Infrastructure for the re-routing costs with a new tariff and requires the pipeline to be back in service no later than July 2029. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Additionally, in December 2025, Sempra Infrastructure and the CFE entered into a non-binding agreement for potential equity participation in the Guaymas-El Oro segment of the Sonora pipeline.
We estimate the capital expenditures for re-routing the pipeline will be approximately $260 million, including capitalized interest and project contingency. The actual amount of capital expenditures may differ substantially from our estimates.
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The Guaymas-El Oro segment of the Sonora pipeline currently constitutes a Sole Risk Project under the terms of the SI Partners limited partnership agreement, which means that Sempra Infrastructure holds a 100% interest in the project. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability and Sempra Infrastructure receives, through the acquisition of Sole Risk Interests, any economic and other benefits from such projects. The Guaymas-El Oro segment of the Sonora pipeline will continue to be owned by and a Sole Risk Project of Sempra after closing the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6 of the Notes to Consolidated Financial Statements. Any proceeds from a sale of the Guaymas-El Oro segment of the Sonora pipeline would be split between Sempra (90%) and ADIA (10%), subject to adjustments.
At December 31, 2025, Sempra Infrastructure had $389 million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if, among other things, Sempra Infrastructure is unable to re-route a portion of the pipeline and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery, which in each case could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Low Carbon Solutions
Cimarrón Wind. The Cimarrón Wind project, an approximately 320-MW wind generation facility in Baja California, Mexico, commenced energy generation in October 2025 during its commissioning phase. We estimate the capital expenditures for the project will be approximately $550 million, including capitalized interest at the project level and project contingency. The actual amount of capital expenditures may differ substantially from our estimates. We expect commercial operations to commence in the first quarter of 2026.
Hackberry Carbon Sequestration Project. SI Partners is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana, together with TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation. This proposed project is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility, the proposed Cameron LNG Phase 2 project and potentially other sources. In April 2025, the Louisiana Department of Conservation and Energy (LDC&E), formally known as the Louisiana Department of Energy and Natural Resources, issued a draft Class VI carbon injection well construction permit and held the required public hearing. In September 2025, LDC&E issued the final permit to construct a Class VI carbon injection well.
Legal and Regulatory Matters
See Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors” for discussions of the following legal and regulatory matters affecting our operations in Mexico and risks associated with Mexican laws, policies and government influence:
▪ Energía Costa Azul
◦ Land Disputes
◦ Environmental and Social Impact Permits
▪ Mexican Government Influence on Economic and Energy Matters
One or more unfavorable conclusions on these land disputes, environmental and social impact permit challenges, and regulatory and other actions by the Mexican government could materially adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the site of the ECA Regas Facility and have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
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SOURCES AND USES OF CASH
We discuss herein our sources and uses of cash for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion of our sources and uses of cash for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “ Part II – Item 7. MD&A – Sources and Uses of Cash ” in our 2024 annual report on Form 10-K filed with the SEC on February 25, 2025.
The following tables include only significant changes in cash flow activities for each of the Registrants.
CASH FLOWS FROM OPERATING ACTIVITIES
(Dollars in millions)
Years ended December 31,
Sempra
SDG&E
SoCalGas
Change
Change in regulatory accounts, current and noncurrent
Change in accounts receivable
Change in income taxes receivable/payable, net
Satisfaction of performance obligations related to a contract modification
Change in net margin posted, current and noncurrent
Higher (lower) net income, adjusted for noncash items included in earnings
Customer ’ s early termination of firm transportation agreements
Change in noncurrent qualified pension assets/liabilities, net
Change in fixed-price contracts and other derivatives, current and noncurrent
Change in accrued franchise fees
Change in GHG allowances, current and noncurrent
Change in accounts payable
Other
CASH FLOWS FROM INVESTING ACTIVITIES
(Dollars in millions)
Years ended December 31,
Sempra
SDG&E
SoCalGas
Change
(Increase) decrease in capital expenditures
Higher contributions to Oncor Holdings
Other
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CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Years ended December 31,
Sempra
SDG&E
SoCalGas
Change
Contributions from CRNCI, net of transaction costs
Change in borrowings and repayments of short-term debt, net
Higher (lower) issuances of short-term debt with maturities greater than 90 days
Higher issuances of long-term debt
Proceeds from investor equity subscription
Higher advances from unconsolidated affiliates
Termination of interest rate swaps
Higher common dividends paid
Higher distributions to NCI
Higher payments on short-term debt with maturities greater than 90 days
Redemption of preferred stock
Lower contributions from NCI
Lower issuances of common stock
(Higher) lower payments on long-term debt and finance leases
Other
Capital Expenditures for PP&E
We invested most of our capital expenditures at Sempra Infrastructure, primarily for LNG projects in development and under construction, and at Sempra California, primarily for transmission and distribution improvements, including pipeline and wildfire safety. The following table summarizes, by segment, capital expenditures for PP&E for the last three years.
CAPITAL EXPENDITURES FOR PP&E
(Dollars in millions)
Years ended December 31,
Sempra:
Sempra California (1)
Sempra Infrastructure
Segment totals
Parent and other
Total Sempra
(1) Includes capital expenditures for PP&E of $2,427, $2,522, and $2,540 at SDG&E and $2,116, $2,231, and $2,020 at SoCalGas for 2025, 2024, and 2023, respectively.
Capital Expenditures for Investments
The following table summarizes, by segment, capital expenditures for investments in entities that we account for under the equity method for the last three years.
CAPITAL EXPENDITURES FOR INVESTMENTS
(Dollars in millions)
Years ended December 31,
Sempra:
Sempra Texas Utilities
Sempra Infrastructure
Total Sempra
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Future Capital Expenditures for PP&E and Investments
The amounts and timing of capital expenditures for PP&E and certain investments are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC, the FERC and the PUCT, and various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors.” We expect to make capital expenditures for PP&E, including capitalized interest and AFUDC related to debt, and investments of approximately $8.6 billion in 2026 and $38.7 billion during the five-year period covered by our 2026 through 2030 capital expenditures plan, as summarized by segment in the following table.
FUTURE CAPITAL EXPENDITURES FOR PP&E AND INVESTMENTS
(Dollars in millions)
Year ending December 31, 2026
Capital plan for 2026 - 2030
Sempra:
Sempra California (1)
Sempra Texas Utilities
Sempra Infrastructure (2)
Total Sempra
(1) Includes expected future capital expenditures of $2,200 and $2,100 at SDG&E and SoCalGas, respectively, for the year ending December 31, 2026 and $12,900 and $10,600 at SDG&E and SoCalGas, respectively, during the period covered by their 2026 through 2030 capital expenditures plans.
(2) Sempra's Capital Plan assumes Sempra's 70% consolidated ownership of SI Partners for the first three months of 2026 and 25% thereafter, which represents Sempra's remaining interest under the equity method upon completion of the sale of a 45% equity interest in SI Partners.
We expect the majority of our capital expenditures for PP&E and investments in 2026 will relate to investments in transmission and distribution safety and reliability at our regulated public utilities and construction of the PA LNG Phase 1 project and PA LNG Phase 2 project at Sempra Infrastructure.
When (i) including Sempra’s proportionate ownership interest in expected capital expenditures for PP&E at unconsolidated equity method investees while excluding Sempra’s expected capital contributions to those unconsolidated equity method investees and (ii) excluding NCI’s proportionate ownership interest in expected capital expenditures for PP&E at Sempra and at unconsolidated equity method investees, we expect capital expenditures for PP&E from 2026 through 2030 to total $64.9 billion.
Oncor announced a new five-year base capital expenditures plan from 2026 through 2030 of approximately $47.5 billion, which is 32% higher than Oncor’s 2025 through 2029 base capital expenditures plan. This increase is largely attributable to Oncor’s targeted completion by December 31, 2030 of its Permian Basin Reliability Plan projects, as well as other new transmission projects and distribution upgrades. Oncor’s base capital expenditures plan does not include certain incremental capital expenditure opportunities, including various transmission and customer interconnection projects, that may be completed over the 2026 through 2030 period and could potentially increase its five-year base capital expenditures plan by as much as $10.0 billion over that period. 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.
Periodically, we review our construction, investment and financing programs and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, safety and environmental requirements, and other relevant factors.
Our level of capital expenditures for PP&E and investments in the next few years may differ substantially from our estimates and will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in tax law and business opportunities providing desirable rates of return, among various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors.” We aim to finance our capital expenditures for PP&E and investments in a manner that will maintain our investment-grade credit ratings and capital structure, but we may not be able to do so.
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Rate Base
For SDG&E and SoCalGas, rate base is the value of assets on which SDG&E and SoCalGas are permitted to earn a specified rate of return in accordance with rules set by regulatory agencies, including the CPUC and the FERC (for SDG&E), which is calculated using a 13-month average pursuant to CPUC methodology as adopted in rate-setting proceedings. The following table summarizes the weighted-average rate base for SDG&E and SoCalGas for the last three years.
WEIGHTED-AVERAGE RATE BASE
(Dollars in millions)
SDG&E
SoCalGas
The increase in weighted-average rate base reflects the significant capital investments that SDG&E and SoCalGas have made in transmission and distribution safety and reliability. We expect the weighted-average rate base to continue to increase in 2026 and beyond based on our expected capital investments.
For Oncor, rate base represents the total invested capital, as adjusted in accordance with PUCT rules, at the end of the previous calendar year as reported in the Earnings Monitoring Report filed with the PUCT on an annual basis. Oncor’s regulatory rate base as reported in these filings as of December 31, 2024 and 2023 was $26.6 billion and $23.1 billion, respectively. As calculated on a similar basis, its estimated regulatory rate base at December 31, 2025 was $31.5 billion. The increase in rate base reflects the significant capital investments that Oncor has made in its transmission and distribution system, and we expect rate base to continue to increase in 2026 and beyond based on Oncor’s expected capital investments.
Capital Stock Transactions
Sempra
Cash provided by issuances of common stock was:
▪ $32 million in 2025
▪ $1,219 million in 2024
▪ $145 million in 2023
Cash used for repurchases of common stock was:
▪ $58 million in 2025
▪ $43 million in 2024
▪ $32 million in 2023
We discuss the issuances and repurchases of common stock in Note 13 of the Notes to Consolidated Financial Statements.
Dividends
Sempra
Sempra paid cash dividends of:
▪ $1,603 million for common stock and $40 million for preferred stock in 2025
▪ $1,499 million for common stock and $44 million for preferred stock in 2024
▪ $1,483 million for common stock and $44 million for preferred stock in 2023
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DIVIDENDS PER SHARE ON SEMPRA COMMON STOCK
(As approved by our board of directors)
On February 25, 2026, our board of directors declared a dividend of $0.6575 per share on our common stock payable on April 15, 2026.
All declarations of dividends on our common stock are made at the discretion of the board of directors. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend on earnings, cash flows, financial and legal requirements, and other relevant factors at that time. As a result, Sempra’s dividends on common stock declared on a historical basis may not be indicative of future declarations.
SDG&E
In 2025, 2024 and 2023, SDG&E paid common stock dividends to Enova Corporation and Enova Corporation paid corresponding dividends to Sempra of $200 million, $225 million and $100 million, respectively. SDG&E’s dividends on common stock declared on an annual historical basis may not be indicative of future declarations.
Enova Corporation, a wholly owned subsidiary of Sempra, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova Corporation and dividends paid by Enova Corporation to Sempra are eliminated in Sempra’s consolidated financial statements.
SoCalGas
In 2025, 2024 and 2023, SoCalGas paid common stock dividends to Pacific Enterprises and Pacific Enterprises paid corresponding dividends to Sempra of $200 million, $200 million and $100 million, respectively. SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations.
Pacific Enterprises, a wholly owned subsidiary of Sempra, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to Pacific Enterprises and dividends paid by Pacific Enterprises to Sempra are eliminated in Sempra’s consolidated financial statements.
Dividend Restrictions
The board of directors for each of Sempra, SDG&E and SoCalGas has the discretion to determine whether to declare and, if declared, the amount of any dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra. At December 31, 2025, based on these regulations, Sempra could have received combined loans and dividends of approximately $868 million from SDG&E and $350 million from SoCalGas.
We provide additional information about dividend restrictions in “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements and in Note 13 of the Notes to Consolidated Financial Statements.
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Capitalization
Our total capitalization, which is the sum of total debt and equity, and our debt-to-capitalization ratio, which is calculated as total debt as a percentage of total capitalization, was as follows:
TOTAL CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIO
(Dollars in millions)
Total capitalization
Debt-to-capitalization ratio
December 31,
Sempra
SDG&E
SoCalGas
In 2025 compared to 2024, Sempra’s total capitalization increased by $8.3 billion (11%) due to:
▪ increase in long-term debt, which includes long-term debt that is within the disposal group that is classified as held for sale
▪ increase in equity primarily from contributions from CRNCI and NCI, as well as comprehensive income exceeding dividends
Offset by:
▪ redemption of preferred stock and distributions to NCI
In 2025 compared to 2024, SDG&E’s and SoCalGas’ total capitalization increased by $1.3 billion (6%) and $1.3 billion (8%), respectively, due to increases in debt and increases in equity from comprehensive income exceeding dividends.
CRITICAL ACCOUNTING ESTIMATES
Management views the accounting estimates that we describe below as critical because their application is the most relevant, judgmental and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these critical accounting estimates, which are material to our financial statements with the Audit Committee of Sempra’s board of directors.
REGULATORY ACCOUNTING
Sempra, SDG&E, SoCalGas
As regulated entities, SDG&E’s and SoCalGas’ customer rates, as set and monitored by regulators, are designed to recover the cost of providing service and to provide the opportunity to realize their authorized rates of return on their investments. SDG&E and SoCalGas assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as:
▪ changes in the regulatory and political environment or the utility’s competitive position
▪ issuance of a regulatory commission order
▪ passage of new legislation
To the extent that circumstances associated with regulatory balances change, the regulatory balances are evaluated and adjusted if appropriate.
Significant management judgment is required to evaluate the anticipated recovery of regulatory assets and revenues subject to refund, as well as the existence and amount of regulatory liabilities. Adverse regulatory or legislative actions could materially impact the amounts of our regulatory assets and liabilities and could materially adversely impact our results of operations and financial condition. Specifically, if future recovery of costs ceases to be probable, all or part of the associated regulatory assets would need to be written off against current period earnings, or adverse regulatory or legislative actions could give rise to material new or higher regulatory liabilities. We discuss details of SDG&E’s and SoCalGas’ regulatory assets and liabilities and additional factors that management considers when assessing probabilities associated with regulatory balances in Notes 1, 4, 15 and 16 of the Notes to Consolidated Financial Statements.
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INCOME TAXES
Sempra, SDG&E, SoCalGas
Our income tax expense and related balance sheet amounts involve significant management judgments and estimates. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. When we evaluate the anticipated resolution of income tax issues, we consider:
▪ past resolutions of the same issue or similar issues
▪ the status of any income tax examination in progress
▪ positions taken by taxing authorities with other taxpayers with similar issues
The likelihood of deferred income tax recovery is based on analyses of the deferred income tax assets and our expectation of future taxable income, based on our strategic planning. Should a change in facts or circumstances lead to a change in judgment about the ultimate realizability of a deferred tax asset, we would record or adjust the related valuation allowance in the period that the change in facts and circumstances occurs, along with a corresponding increase or decrease in the provision for income taxes.
Actual income taxes could vary from estimated amounts because of:
▪ future impacts of various items, including changes in tax laws, regulations, interpretations and rulings
▪ our financial condition in future periods
▪ the resolution of various income tax issues between us and taxing and regulatory authorities
Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our results of operations, financial condition and cash flows.
We discuss these matters and additional information related to accounting for income taxes, including uncertainty in income taxes, in Note 8 of the Notes to Consolidated Financial Statements.
PENSION AND PBOP PLANS
Sempra, SDG&E, SoCalGas
To measure our pension and PBOP obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We review these assumptions annually and update when appropriate.
The critical assumptions used to develop the required estimates include the following key factors:
▪ discount rates
▪ expected return on plan assets
▪ health care cost trend rates
▪ interest crediting rate on cash balance accounts
▪ mortality rate
▪ rate of compensation increases
▪ termination and retirement rates
▪ utilization of postretirement welfare benefits
▪ payout elections (lump sum or annuity)
▪ lump sum interest rates
The actuarial assumptions we use may differ materially from actual results due to:
▪ return on plan assets
▪ changing market and economic conditions
▪ higher or lower withdrawal rates
▪ longer or shorter participant life spans
▪ more or fewer lump sum versus annuity payout elections made by plan participants
▪ higher or lower retirement rates
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Changes in the estimated costs or timing of pension and PBOP, or the assumptions and judgments used by management underlying these estimates (primarily the discount rate and expected return on plan assets), as well as changes in the circumstances associated with rate recovery, could have a material effect on the recorded expenses and liabilities. The following tables summarize the impact to our projected benefit obligation for pension and accumulated benefit obligation for PBOP at December 31, 2025, and 2025 net periodic benefit costs, in each case if the discount rate or expected return on plan assets were changed by 1%.
IMPACT DUE TO INCREASE/DECREASE IN DISCOUNT RATE
(Dollars in millions)
Sempra
SDG&E
SoCalGas
Increase
Decrease
Increase
Decrease
Increase
Decrease
Pension:
(Decrease) increase to projected benefit obligation,
net
(Decrease) increase to net periodic benefit cost
PBOP:
(Decrease) increase to accumulated benefit
obligation, net
(Decrease) increase to net periodic benefit cost
IMPACT DUE TO INCREASE/DECREASE IN RETURN ON PLAN ASSETS
(Dollars in millions)
Sempra
SDG&E
SoCalGas
Increase
Decrease
Increase
Decrease
Increase
Decrease
Pension:
(Decrease) increase to net periodic benefit cost
PBOP:
(Decrease) increase to net periodic benefit cost
For SDG&E and SoCalGas plans, the effects of the assumptions on earnings are expected to be recovered in rates and therefore are offset in regulatory accounts. We provide details of our pension and PBOP plans in Note 9 of the Notes to Consolidated Financial Statements.
SONGS ASSET RETIREMENT OBLIGATIONS
Sempra, SDG&E
SDG&E’s legal AROs related to the decommissioning of SONGS are estimated based on a site-specific study performed no less than every three years. The estimate of the obligations includes:
▪ estimated decommissioning costs, including labor, equipment, material and other disposal costs
▪ inflation adjustment applied to estimated cash flows
▪ discount rate based on a credit-adjusted risk-free rate
▪ actual decommissioning costs, progress to date and expected duration of decommissioning activities
SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s NDT.
SDG&E’s ARO related to the decommissioning of SONGS was $446 million as of December 31, 2025, based on the decommissioning cost study prepared in 2024. Changes in the estimated costs, execution strategy or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission this facility, which could have a material effect on the recorded liability.
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The following table illustrates the increase to SDG&E’s and Sempra’s ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:
INCREASE TO ARO AND REGULATORY ASSET
(Dollars in millions)
December 31, 2025
Uniform increase in escalation percentage of 1%
The increase in the ARO liability driven by an increase in the cost escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities. We provide additional detail in Note 15 of the Notes to Consolidated Financial Statements.
IMPAIRMENT TESTING OF LONG-LIVED ASSETS
Sempra
Whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the asset. If so, we estimate the fair value of the asset to determine the extent to which carrying value exceeds fair value. For such an estimate, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful life of a long-lived asset and to determine our intent to use the asset. Our intent to use or dispose of a long-lived asset is subject to re-evaluation and can change over time. If such an impairment test is required, the fair value of a long-lived asset can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. Critical assumptions that affect our estimates of fair value may include:
▪ consideration of market transactions
▪ future cash flows
▪ the appropriate risk-adjusted discount rate, including the impacts of country risk and entity risk
We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements.
IMPAIRMENT TESTING OF GOODWILL
Sempra
When determining if goodwill is impaired, the fair value of the reporting unit can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a goodwill impairment may or may not be required. When we perform a quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and compare that to its carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as a discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include:
▪ consideration of market transactions
▪ future cash flows
▪ projected revenue and expense growth rates
▪ the appropriate risk-adjusted discount rate, including the impacts of country risk, customer creditworthiness and entity risk
At December 31, 2025, goodwill is classified as held for sale. In 2025, we performed a quantitative goodwill impairment test and determined that the estimated fair values of our reporting units in Mexico to which goodwill was allocated were substantially above their respective carrying values as of October 1, our annual goodwill impairment testing date. Upon performing a qualitative analysis as of October 1, 2024, we determined that it was not more likely than not that the fair value of such reporting units was less than their respective carrying values. Our goodwill impairment test is determined based on assumptions existing as of that point in time. Changes in the business (such as loss of future cash flows from customer disputes, renegotiation of customer contracts or the macroeconomic environment, including rising interest rates) may result in us having to perform an interim goodwill impairment test, which could result in an impairment of our goodwill.
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NEW ACCOUNTING STANDARDS
We discuss the recent accounting pronouncements that have had or may have a significant effect on our financial statements and/or disclosures in Note 2 of the Notes to Consolidated Financial Statements.
