SEMPRA (SRE) Business

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:

(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:

(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.

(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.

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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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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

(1)    Ages are as of February 26, 2026.

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(1)    Ages are as of February 26, 2026.

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(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.

(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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