Sempra: Form 10-K for the period ended Dec 31, 2023

OVERVIEW

We are a California-based holding company with energy infrastructure investments in North America. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers.

Sempra was formed in 1998 through a business combination of Enova and PE, 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

Our mission is to be North America’s premier energy infrastructure company. We are primarily focused on transmission and distribution investments, among other areas, that we believe are capable of producing stable cash flows and earnings visibility, with the goals of delivering safe, reliable and increasingly clean forms of energy to customers and 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

In the fourth quarter of 2023, Sempra realigned its reportable segments to reflect changes in how the CODM oversees our three platforms: Sempra California, Sempra Texas Utilities and Sempra Infrastructure. Our former SDG&E and SoCalGas reportable segments were combined into one operating and reportable segment, Sempra California, which is consistent with how the CODM assesses performance due to the similarities of their operations, including geographic location and regulatory framework in California. Sempra’s historical segment disclosures have been restated to conform with the current presentation, so that all discussions reflect the revised segment information of its three reportable segments.

SDG&E and SoCalGas each has one reportable segment.

Sempra California

SDG&E

SDG&E is a regulated public utility that provides electric services to a population of, at December 31, 2023, 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, 2023 covered the following territory:

We describe SDG&E’s electric utility operations below. We describe SDG&E’s natural gas utility operations in “Sempra California’s Natural Gas Utility Operations.”

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 1,925 miles of transmission lines, 24,023 miles of distribution lines and 157 substations at December 31, 2023. 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 and operated by the California ISO. Both of these lines together provide SDG&E with import capability of 3,900 MW of power.

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.

Edison’s transmission system is connected to SDG&E’s 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, 2023 were as follows:

ELECTRIC RESOURCES(1)

(1) Excludes approximately 367 MW of energy storage owned and approximately 585 MW of energy storage contracted.

(2) SDG&E owns and operates four natural gas-fired power plants, three of which are in California and one is in Nevada.

Charges under contracts with suppliers are based on the amount of energy received or are tolls based on available capacity. Tolling contracts are PPAs under which SDG&E provides natural gas to the energy supplier.

SDG&E procures natural gas under short-term contracts for its owned generation facilities and for certain tolling contracts associated with PPAs. Purchases from various southwestern U.S. suppliers are primarily priced based on published monthly bid-week indices, which can be subject to volatility.

SDG&E participates in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers throughout the U.S. and Canada. Participants can make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.

Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:

ELECTRIC CUSTOMER METERS AND VOLUMES

(1) Includes intercompany sales.

SDG&E currently provides procurement service for a portion of its customer load. Most customers receive procurement 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 departing load. Accordingly, SDG&E’s CCA and DA customers receive primarily transportation and distribution services from SDG&E.

CCA is only available if the customer’s local jurisdiction (city or county) offers such a program, as is the case with the City of San Diego and certain other jurisdictions in SDG&E’s service territory, and DA is currently limited by a cap based on gigawatt hours. Several jurisdictions in SDG&E's territory have implemented CCA, including the City of San Diego in 2022. Additional jurisdictions are in the process of implementing or considering CCA.

As a result of customers electing CCA and DA services, 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 purpose of the framework is to help ensure SDG&E’s procurement cost obligations are more equitably shared among customers served by SDG&E and customers now served by CCA and DA.

San Diego’s mild climate and SDG&E’s robust energy efficiency programs contribute to lower consumption by our customers. Rooftop solar installations continue to reduce residential and commercial volumes sold by SDG&E. At December 31, 2023, 2022 and 2021, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 2,154 MW, 1,864 MW and 1,620 MW, respectively.

Electricity demand is dependent on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, renewable power generation, the effectiveness of energy efficiency programs, demand-side management impact and distributed generation resources. California’s energy policy supports increased electrification, particularly electrification of vehicles, which could significantly increase sales volumes in the coming years. Other external factors, such as the price of purchased power, the use of hydroelectric power, the use of and further development of renewable energy resources 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 solar installations. 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.

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, 2023, approximately 21 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, 2023 covered the following territory:

We describe SoCalGas’ natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.”

Sempra California’s Natural Gas Utility Operations

Natural Gas Procurement and Transportation. At December 31, 2023, SoCalGas’ natural gas facilities included 3,043 miles of transmission and storage pipelines, 52,404 miles of distribution pipelines, 48,983 miles of service pipelines and nine transmission compressor stations, and SDG&E’s natural gas facilities consisted of 197 miles of transmission pipelines, 9,135 miles of distribution pipelines, 6,737 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 interconnect 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 renewable natural gas producers.

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 sources, 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 monthly bid week 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 128 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 CPUC limitations, represents 63% of SoCalGas’ working natural gas storage capacity. At December 31, 2023, SoCalGas has been authorized by the CPUC to utilize up to 68.6 Bcf of working gas at the facility to help achieve reliability for the region as determined by the CPUC. The authorized storage capacity of the Aliso Canyon natural gas storage facility is subject to an ongoing proceeding with the CPUC that we discuss in Note 16 of the Notes to Consolidated Financial Statements, in “Part I – Item 1A. Risk Factors” and in “Part II – Item 7. MD&A – Capital Resources and Liquidity – SoCalGas.”

Customers and Demand. SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers in its territory and SDG&E’s territory on a combined portfolio basis. SoCalGas also offers natural gas transportation and storage services for others.

NATURAL GAS CUSTOMER METERS AND VOLUMES

(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 their core customers.

Noncore customers at SoCalGas 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.

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 preference, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs. Other external factors such as weather, the price of, demand for, and supply sources of electricity, the use of and further development of renewable energy resources 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 sources for 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 hydroelectric generation and other renewable energy sources. Given the significant quantity 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 tends to increase in the winter months to meet the heating load. 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.

Sempra Texas Utilities

Sempra Texas Utilities is comprised of our equity method investments in Oncor Holdings and Sharyland Holdings. Oncor Holdings is an indirect, wholly owned entity of Sempra that owns an 80.25% interest in Oncor. TTI owns the remaining 19.75% interest in Oncor. Sempra owns an indirect 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities.

Sempra Texas Utilities’ assets at December 31, 2023 covered the following territory:

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, 2023, Oncor had 4,774 employees, including 819 employees covered under a collective bargaining agreement.

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 issues 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, 2023, Oncor’s transmission system included approximately 18,298 circuit miles of transmission lines, a total of 1,257 transmission and distribution substations, and interconnection to 173 third-party generation facilities totaling 54,277 MW.

Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to limited interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. 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 3,722 distribution feeders at December 31, 2023.

Oncor’s distribution system included nearly 4.0 million points of delivery at December 31, 2023 and consisted of 125,116 circuit miles of overhead and underground lines.

Distribution revenues from residential and small business users are 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.

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, delivering electricity to nearly 4.0 million homes and businesses, operating more than 143,000 circuit miles of transmission and distribution lines as of December 31, 2023 in a territory with an estimated population of approximately 13 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. Rather, 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, 2023, 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 single certificated, with Oncor as the only certificated electric transmission and distribution provider. However, in multi-certificated areas of Texas, Oncor competes with certain other 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 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, 2023, 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.

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, builds, operates and invests in energy infrastructure to help enable the energy transition in North American markets and globally.

At December 31, 2023, Sempra Infrastructure, KKR Pinnacle and ADIA directly or indirectly own a 70%, 20%, and 10% interest, respectively, in SI Partners. SI Partners holds a 100% ownership interest in Sempra LNG Holding, LP and a 99.9% ownership interest in IEnova at December 31, 2023. 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.

At December 31, 2023, Sempra Infrastructure owned or held interests in the following assets:

LNG

Sempra Infrastructure’s LNG business line is comprised of a natural gas liquefaction and regasification portfolio in operation, construction or development, and is focused on securely delivering natural gas to the world in support of the energy transition.

Cameron LNG Phase 1 Facility. SI Partners owns 50.2% of Cameron LNG JV, while 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. We account for our 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. Sempra Infrastructure 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 firm storage service fees under firm storage service agreements and nitrogen injection service agreements with Shell México Gas Natural, S. de R.L. de C.V. and SEFE that expire in 2028, which permit them to collectively use 50% of the terminal’s capacity, with the remaining 50% of the capacity available for Sempra Infrastructure’s use. The land on which the ECA Regas Facility and the ECA LNG liquefaction projects under construction and in development are expected to be situated, as well as land adjacent to those properties, are the subject of litigation. We discuss litigation over land disputes and environmental and social impact permits at the ECA Regas Facility in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.”

Sempra Infrastructure uses its 50% capacity at the ECA Regas Facility to satisfy its obligation under an LNG SPA with Tangguh PSC through 2029, which we discuss below, and ECA LNG Phase 1 will be the sole user of this capacity thereafter.

ECA LNG Phase 1 Project. SI Partners owns an 83.4% interest in ECA LNG Phase 1, and an affiliate of TotalEnergies SE owns the remaining 16.6% interest. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We expect the ECA LNG Phase 1 project to commence commercial operations in the summer of 2025.

ECA LNG Phase 1 has definitive 20-year SPAs with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG and Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG.

The construction of the ECA LNG Phase 1 project is subject to numerous risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

PA LNG Phase 1 Project. SI Partners, KKR Denali and an affiliate of ConocoPhillips directly or indirectly own a 28%, 42% and 30%, respectively, interest 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. We expect the first and second trains of the PA LNG Phase 1 project to commence commercial operations in 2027 and 2028, respectively.

Sempra Infrastructure has definitive SPAs with an affiliate of ConocoPhillips for a 20-year term for 5 Mtpa of LNG, RWE Supply & Trading GmbH for a 15-year term for 2.25 Mtpa of LNG, INEOS for a 20-year term for approximately 1.4 Mtpa of LNG, ORLEN for a 20-year term for approximately 1 Mtpa of LNG, and ENGIE S.A. for a 15-year term for approximately 0.875 Mtpa of LNG.

The construction of the PA LNG Phase 1 project is subject to numerous risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

Asset and Supply Optimization. Sempra Infrastructure 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. Sempra Infrastructure 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. Sempra Infrastructure 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, Sempra Infrastructure may purchase natural gas in the market to satisfy such commitment.

Sempra Infrastructure purchases, transports and sells natural gas, and has customers in both the U.S. and Mexico, including the CFE. Sempra Infrastructure 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.

LNG Projects Under Development. Sempra Infrastructure is evaluating the following development opportunities:

• Cameron LNG Phase 2 project, an expansion of the Cameron LNG Phase 1 facility that would add one 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 Sempra Infrastructure’s existing ECA Regas Facility in Baja California, Mexico
• PA LNG Phase 2 project, a large-scale natural gas liquefaction project and associated infrastructure to be located adjacent to the PA LNG Phase 1 project in the vicinity of Port Arthur, Texas
• Vista Pacifico LNG project, a mid-scale natural gas liquefaction project and associated infrastructure in the vicinity of Topolobampo in Sinaloa, Mexico

No final investment decision has been reached for any of these potential projects. The development of these projects is subject to numerous risks and uncertainties. For a discussion of these proposed projects and their risks, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

Demand and Competition. North America benefits from numerous competitive advantages as a potential supplier of LNG to world markets, including the following:

• high levels of developed and undeveloped natural gas resources, including unconventional natural gas and tight 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

Brownfield liquefaction projects also benefit from the particular competitive advantage of the proximity of pre-existing infrastructure, such as LNG tankage and berths.

Global LNG 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 and 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. Sempra Infrastructure develops, builds, operates and invests in systems for the receipt, transportation, compression and delivery of natural gas and ethane. At December 31, 2023, these systems consisted of 1,850 miles of natural gas transmission pipelines plus 136 miles under construction, 16 natural gas compression stations plus one under construction, and 139 miles of ethane pipelines in Mexico. The design capacity of these pipeline assets is over 16,400 MMcf per day of natural gas, 204 MMcf per day of ethane gas and 106,000 barrels per day of ethane liquid. Capacity on Sempra Infrastructure’s 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, SEFE and other similar counterparties.

Sempra Infrastructure owns a 40-mile natural gas pipeline in south Louisiana, the Cameron Interstate Pipeline, which 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.

Sempra Infrastructure has made a positive final investment decision on and begun procurement and engineering activities related to the construction of the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana.

Natural Gas Distribution. Sempra Infrastructure’s natural gas distribution regulated utility, Ecogas, operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. At December 31, 2023, Ecogas had approximately 3,043 miles of distribution pipeline, and approximately 157,000 customer meters serving more than 597,000 residential, commercial and industrial consumers with sales volume of approximately 10 MMcf per day in 2023. Ecogas relies on supply and transportation services from Sempra Infrastructure, SoCalGas and PEMEX for the natural gas it distributes to its customers.

LPG Storage and Associated Systems. Sempra Infrastructure owns and operates the TDF, S. de R. L. de C. V. (TDF) pipeline system and the Guadalajara LPG terminal. At December 31, 2023, 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 Sempra Infrastructure’s 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. Sempra Infrastructure’s 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. Sempra Infrastructure’s refined products storage business develops, constructs 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, Puebla, Sinaloa, Veracruz and Valle de México for private companies, with a combined storage capacity of 4.6 million barrels fully operating or under construction/commissioning as of December 31, 2023. Construction of the Topolobampo marine terminal was substantially completed in May 2022, at which time commissioning activities commenced. In December 2023, we received the final pending permit and expect the Topolobampo terminal will commence commercial operations in the second quarter of 2024. 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 and Valero Energy Corporation. The contracted rate under these contracts is independent from each terminal’s regulated rate as determined by the CRE.

Sempra Infrastructure has made a positive final investment decision on and begun procurement and engineering activities related to the construction of Louisiana Storage, a 12.5-Bcf salt dome natural gas storage facility to support 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 in Mexicali, Chihuahua and La Laguna-Durango, Mexico as other distributors of natural gas build or consider building natural gas distribution systems. Sempra Infrastructure’s 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 commercializing and deploying low carbon solutions in support of meeting the demand for lower carbon and reliable energy supply. The portfolio of resources includes renewable energy infrastructure, a natural gas-fired power plant, as well as hydrogen fuel production and advanced carbon capture, usage and storage technologies that are under development.

Renewable Power Generation. Sempra Infrastructure develops, builds, invests in 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, as well as 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, 2023, Sempra Infrastructure had a fully contracted, total nameplate capacity of 1,044 MW related to its fully operating wind and solar power generation facilities. Some of these facilities are impacted by regulatory actions by the Mexican government and related litigation, which we discuss in Note 16 of the Notes to Consolidated Financial Statements, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

RENEWABLE POWER GENERATION

Natural Gas-Fired Generation. Sempra Infrastructure 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 and to governmental, public utility and wholesale power marketing entities.

Low Carbon Solutions Projects Under Development. Sempra Infrastructure is developing the Cimarrón Wind project, an approximately 300-MW wind generation facility in Baja California, Mexico. In October 2022, Sempra Infrastructure entered into a 20-year PPA, as amended, with Silicon Valley Power for the long-term supply of renewable energy to the City of Santa Clara, California, which is subject to Sempra Infrastructure reaching a final investment decision. Cimarrón Wind would utilize Sempra Infrastructure’s existing cross-border high voltage transmission line to interconnect and deliver clean energy to the East County substation in San Diego County. We expect to make a final investment decision in the first half of 2024.

Sempra Infrastructure is also evaluating the Hackberry Carbon Sequestration development opportunity, which is a carbon capture and sequestration project that is intended to reduce emissions at the Cameron LNG Phase 1 facility and proposed Cameron LNG Phase 2 project.

No final investment decision has been reached for any of these potential projects. The development of these projects is subject to numerous risks and uncertainties. For a discussion of these proposed projects and their risks, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”

Demand and Competition. Sempra Infrastructure 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 and greater financial and other resources, which could give them a competitive advantage for such projects.

Generation from Sempra Infrastructure’s renewable energy assets is susceptible to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight. Because Sempra Infrastructure sells power that it generates at its ESJ wind power generation facility into California, Sempra Infrastructure’s future performance and the demand for renewable energy may be impacted by U.S. state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements in California are generally known as the RPS Program. In California, certification of a generation project by the CEC as an eligible renewable energy resource allows the purchase of output from such generation facility to be counted towards fulfillment of the RPS Program requirements, if such purchase meets the provisions of SB X1-2, the California Renewable Energy Resources Act. The RPS Program may affect the demand for output from renewable energy projects developed by Sempra Infrastructure, particularly the demand from California’s utilities. The first and second phases of ESJ, wind power generation facilities that deliver energy into California, have been certified by the CEC and are in compliance with the RPS Program as of December 31, 2023.

TdM competes daily with other generating plants that supply power into the California electricity market. Sempra Infrastructure manages commodity price risk at TdM by using a mix of day ahead sales of energy, energy spreads hedging, ancillary services, and short-term to medium-term capacity sales.

REGULATION

We discuss the material effects of compliance with all 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, and long-term resource procurement, except as described below in “U.S. Federal;”
• has jurisdiction over the proposed construction of major new electric generation, transmission and distribution, and natural gas storage, transmission and distribution 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, reliability and planning, deregulation, competition and the environment; and
• regulates the interactions and transactions of SDG&E and SoCalGas with Sempra and its other affiliates.

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 role includes inspections, investigations and penalty and citation processes 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.

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. California has implemented a program whereby IOUs providing gas service in California will procure a portion of the natural gas they deliver from biomethane. The proportion of biomethane procured will be phased-in with a state-wide, short-term target in 2025 of 17.6 Bcf per year and a medium-term target in 2030 of 72.8 Bcf per year. SDG&E and SoCalGas are allocated 6.77% and 49.26%, respectively, of the 2025 target, and 7.60% and 52.02%, respectively, of the 2030 target. The rules governing this program are administered by the CPUC under SB 1440.

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. Sempra Infrastructure is also subject to the rules and regulations of CARB.

The California Geologic Energy Management Division, the CPUC, and various other state and local agencies regulate the operation and maintenance of SoCalGas’ natural gas storage facilities.

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 those 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, the Texas 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 open-access requirements for all utilities that are subject to the PUCT’s jurisdiction over electric transmission services, including Oncor.

U.S. Federal

SDG&E and SoCalGas are also regulated at the federal level by the FERC, the EPA, the DOE and the 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 transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return on transmission investment, rates of depreciation, electric rates involving sales for resale and the application of the uniform system of accounts. The U.S. Energy Policy Act governs procedures for requests for electric transmission service. The California IOUs’ electric transmission facilities are under the operational control of the California ISO. As member utilities, Oncor and Sharyland Utilities operate within the ERCOT market, which we discuss below. 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 was permanently retired 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 and compliance with these regulations for the entities they regulate in California.

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 distribution 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.

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

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.

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. In June 2021, the City of San Diego approved ordinances granting SDG&E the 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 the next 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 two lawsuits 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 2023 to 2069, including the Los Angeles County franchise, which initially expired in June 2023 and the subsequent extension expired in December 2023. SoCalGas is operating and expects to continue to operate under the terms and provisions of the expired franchise until a new agreement is reached.

Other U.S. Regulation

The FERC regulates certain Sempra Infrastructure 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 Sempra Infrastructure 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.

Sempra Infrastructure’s investment in Cameron LNG JV is 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. Sempra Infrastructure’s other potential natural gas liquefaction projects would, if completed, be subject to similar regulations.

SDG&E, SoCalGas and businesses in which Sempra Infrastructure invests 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.

SDG&E, SoCalGas and Sempra Infrastructure 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 CRE, ASEA, 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.

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 may require periodic renewal.

Sempra Infrastructure 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 Sempra Infrastructure are generally for 30-year terms, with options for renewal under certain regulatory conditions.

Sempra Infrastructure obtains licenses and permits for the construction, operation and expansion of LNG facilities and for the import and export of LNG and natural gas. Sempra Infrastructure also obtains licenses and permits for the construction and operation of facilities for the receipt, storage and delivery of refined products.

Sempra Infrastructure obtains permits, authorizations and licenses for the construction and operation of natural gas storage facilities and pipelines, and in connection with participation in the wholesale electricity market.

Most of the permits and licenses associated with Sempra Infrastructure’s construction and operations are for periods generally in alignment with the construction cycle or expected useful life of the asset and in many cases are greater than 20 years.

RATEMAKING MECHANISMS

Sempra California

General Rate Case Proceedings

A CPUC GRC proceeding is designed to set sufficient base rates 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, which authorize how much SDG&E and SoCalGas can collect from their customers, and provides for attrition, or annual increases in revenue requirements, for each year following the test year.

We discuss the GRC in 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 return on equity or 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 plant and information technology systems investments to support operations.

A cost of capital proceeding also addresses the CCM, which applies in the interim years between required cost of capital applications and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (the 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 1.000% at the end of the measurement period. 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 one-half of the difference between the CCM benchmark rate and the applicable Moody’s utility bond index, subject to regulatory approval. 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 as a whole.

We discuss the cost of capital and CCM in Note 4 of the Notes to Consolidated Financial Statements and in “Part I – Item 1A. Risk Factors.”

Transmission Rate Cases

SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets. The proceeding establishes a ROE 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 on investment. SDG&E makes annual information filings with the FERC in December to update rates for the following calendar year. SDG&E may also file for ROE incentives that might apply under FERC rules. SDG&E’s debt-to-equity ratio is set annually based on the actual ratio at the end of each year.

Incentive Mechanisms

The CPUC applies certain performance-based measures and incentive mechanisms to all California IOUs, under which SDG&E and SoCalGas have earnings potential above the authorized CPUC base operating margin if they achieve or exceed specific performance and operating goals. Generally, for performance-based measures, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.

Other Cost-Based Recovery

The CPUC, and the FERC as it relates to SDG&E, authorize SDG&E and SoCalGas to collect revenue requirements from customers for operating and capital-related costs (depreciation, taxes and return on rate base), including:

• costs to purchase natural gas and electricity;
• costs associated with administering public purpose, demand response, environmental compliance, and customer energy efficiency programs;
• other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management, and wildfire mitigation; and
• 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. Generally, 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 impose various review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including limitations on the program’s total cost, revenue requirement limits or reviews of costs for reasonableness. These procedures 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, their 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 necessarily 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 otherwise 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. Pursuant to these rules, Oncor’s next base rate review must be filed no later than June 2027. The PUCT issued a final order in Oncor’s most recent comprehensive base rate proceeding in April 2023, and rates implementing that order went into effect on May 1, 2023. In June 2023, the PUCT issued an order on rehearing in response to the motions for rehearing filed by Oncor and certain intervenor parties in the proceeding. The order on rehearing made certain technical and typographical corrections to the final order but otherwise affirmed the material provisions of the final order and did not require modification of the rates that went into effect on May 1, 2023. In September 2023, Oncor filed an appeal in Travis County District Court seeking judicial review of certain rate base disallowances and related expense effects of those disallowances in the PUCT’s order on rehearing. On February 22, 2024, the court dismissed the appeal for lack of jurisdiction. Oncor is evaluating whether to appeal that ruling.

Sharyland Utilities’ 2020 rate case became effective in July 2021 and remains effective until the next rate case is finalized, which we expect could be in late 2025.

In addition, PUCT rules allow Texas electric utilities providing wholesale or retail distribution service to file up to two interim rate adjustment applications per year to recover distribution-related investments placed into service between base rate review proceedings. PUCT rules also allow the Texas utilities to file up to two interim rate adjustment applications per year to reflect changes in transmission-related invested capital. These applications for interim rate adjustments between base rate reviews, known as “capital tracker” provisions, are intended to encourage transmission and distribution investments in the electric system to help ensure reliability and efficiency by helping to shorten the time period between a utility’s investment in transmission and distribution infrastructure and its ability to start recovering and earning a return on such investments. However, all investments included in a capital tracker are ultimately subject to prudence review by the PUCT in the next base rate review, after such assets are put into service.

Capital Structure and Return on Equity

In April 2023, the PUCT issued a final order in Oncor’s comprehensive base rate review that set Oncor’s authorized ROE at 9.7%, a decrease from its previously authorized ROE of 9.8%, and maintained Oncor’s authorized regulatory capital structure at 57.5% debt to 42.5% equity.

Sharyland Utilities’ PUCT-authorized ROE is 9.38% and its authorized regulatory capital structure is 60% debt to 40% equity.

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 CRE, which performs a review of rates every five years and monitors prices charged to end-users. In the fourth quarter of 2020, Ecogas filed its rate case for 2021 through 2025, which was approved by the CRE 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 and Water Quality

The natural gas and electric industries are subject to increasingly stringent air quality and GHG emissions standards, such as those established by CARB and the South Coast Air Quality Management District. SDG&E and SoCalGas generally recover the costs to comply with these standards in rates. We discuss GHG emission standards and credits further in Note 1 of the Notes to the Consolidated Financial Statements.

OTHER MATTERS

Information About Our Executive Officers

(1) Ages are as of February 27, 2024.

INFORMATION ABOUT EXECUTIVE OFFICERS

(1) Ages are as of February 27, 2024.

INFORMATION ABOUT EXECUTIVE OFFICERS

(1) Ages are as of February 27, 2024.

Human Capital

Our ability to advance our mission to be North America’s premier energy infrastructure company 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 board in overseeing the corporation’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 Sempra board of directors.

Our overall culture is another important aspect of our ability to advance our mission. We embrace diversity in our workforce and 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-potential employees who represent the communities we serve, and we provide a range of programs to advance those objectives, 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 Sempra’s charitable matching program. 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.

The table below shows the number of employees for each of our Registrants at December 31, 2023, 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 2023 and we maintain constructive relations with our labor unions.

NUMBER OF EMPLOYEES

(1) Excludes employees of equity method investees.

COMPANY WEBSITES

Our Registrants’ website addresses are:

• Sempra – www.sempra.com (http://www.sempra.com)
• SDG&E – www.sdge.com (http://www.sdge.com)
• SoCalGas – www.socalgas.com (http://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.

When evaluating our company and its consolidated entities and any investment in our or their securities, you should carefully consider the following risk factors and all other information contained in this report and the other documents we file with the SEC, including those filed subsequent to this report. We also may be materially harmed by risks and uncertainties not currently known to us or that we currently consider immaterial. If any of these risks occurs, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, our actual results could differ materially from those expressed or implied in our forward-looking statements, and the trading prices of our securities and those of our consolidated entities could decline. These risk factors are not prioritized in order of importance or materiality, and they should be read together with the other information in this report, including in the Consolidated Financial Statements and in “Part II – Item 7. MD&A.”

RISKS RELATED TO SEMPRA

Operational and Structural Risks

Sempra’s ability to pay dividends and meet its obligations largely depends on the performance of its subsidiaries and entities accounted for as equity method investments.

We are a holding company and substantially all the assets that produce our earnings are owned by our subsidiaries or entities we do not control, including equity method investments. Our ability to pay dividends and meet our debt and other obligations largely depends on distributions from our subsidiaries and equity method investments, which in turn depend on their ability to execute their business strategies and generate cash flows in excess of their own expenditures, dividend payments to third-party owners (if any) and debt and other obligations. In addition, entities accounted for as equity method investments, which we do not control, and our subsidiaries are all separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be precluded from doing so by legislation, regulation or contractual restrictions, in times of financial distress or in other circumstances. The inability to access capital from our subsidiaries and entities accounted for as equity method investments could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra’s rights to the assets of its subsidiaries and equity method investments are structurally subordinated to the claims of each entity’s trade and other creditors. When Sempra is a creditor of any such entity, its rights as a creditor are effectively subordinated to any security interest in the entity’s assets and any indebtedness of the entity senior to that held by Sempra. In addition, Sempra may elect to make capital contributions to its subsidiaries, which are not required to be repaid and are structurally subordinated to claims by creditors of the applicable subsidiary.

Sempra’s investments in businesses it does not control exposes us to risks.

We have investments in businesses we do not control or manage or in which we share control. In some cases, we engage in arrangements with or for these businesses that could expose us to risks in addition to our investment, including guarantees, indemnities and loans. For businesses we do not control, we are subject to the decisions of others, which may be adverse to our interest. When we share control of a business with other owners, any disagreements among the owners about strategy, financial, operational, transactional or other important matters could hinder the business from moving forward with key initiatives or taking other actions and could negatively affect the relationships among the owners and the efficient functioning of the business. In addition, irrespective of whether we control these businesses, we could be responsible for liabilities or losses related to these businesses or elect to make capital contributions to these businesses. Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We discuss these investments in Note 6 of the Notes to Consolidated Financial Statements.

Our business could be negatively affected by activist shareholders.

We have been and may in the future be subject to activist shareholder attention. Activist shareholders may engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes in or assert influence on our board of directors and management. In taking these steps, activist shareholders could seek to acquire our capital stock, which at certain ownership levels could threaten our ability to use some or all our NOL or tax credit carryforwards if our corporation experiences an “ownership change” under applicable tax rules. Responding to activist shareholders can be costly and time-consuming and requires time and attention by our board of directors and management, diverting their attention from our business strategies.

Any actual or perceived instability in our future direction, inability to execute our strategies, or changes in our board of directors or management team arising from activist shareholder campaigns could be exploited by our competitors and/or other activist shareholders, result in the loss of business opportunities, and make it more difficult to pursue our strategic initiatives or attract and retain qualified personnel and business partners, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Financial and Capital Stock-Related Risks

Settlement provisions contained in our equity forward sale agreements subject us to certain risks.

The counterparties to the November 2023 forward sale agreements Sempra entered into in connection with its common stock offering that we discuss in Note 14 of the Notes to Consolidated Financial Statements (collectively, the forward purchasers) have the right to accelerate their respective forward sale agreements (or, in certain cases, the portion thereof that they determine is affected by the relevant event) and require us to physically settle such forward sale agreements on a date specified by the forward purchasers if, among other things and subject to a prior notice requirement:

• they are unable to establish, maintain or unwind their hedge position with respect to the forward sale agreements;
• they determine that they are unable to continue to borrow in a commercially reasonable manner a sufficient number of shares of our common stock or that they would incur a rate that is greater than the cost to borrow shares specified in the forward sale agreements;
• we declare or pay cash dividends on shares of our common stock before or in an amount that exceeds those prescribed by the forward sale agreements;
• announcement of certain extraordinary events such as certain mergers and tender offers, insolvency and the delisting of our common stock, or an event occurs that would constitute a hedging disruption or change in law;

The forward purchasers’ decision to exercise their right to accelerate the forward sale agreements (or, in certain cases, the portion thereof that they determine is affected by the relevant event) and to require us to settle the forward sale agreements will be made irrespective of our interests, including our need for capital. In such cases, we could be required to issue and deliver our common stock under the terms of the physical settlement provisions of the forward sale agreements irrespective of our capital needs, which would result in dilution to our EPS and may adversely affect the market price of our common stock, our preferred stock, any other equity that we may issue and our debt securities.

If the forward purchasers do not exercise the right to accelerate the forward sale agreements, we are required to fully settle these forward sale agreements prior to December 31, 2024, which we expect to do entirely by delivery of shares of our common stock under physical settlement. Subject to the provisions of the forward sale agreements, delivery of our shares upon physical or net share settlement of the forward sale agreements will result in dilution to our EPS and may adversely affect the market price of our common stock, our preferred stock and any other equity that we may issue.

If we elect to cash or net share settle all or a portion of the shares of our common stock underlying the forward sale agreements, we would expect to issue a substantially lower number of shares than if we settled by physical delivery, but would not receive the cash for the shares that would have otherwise been issued if we settled the entire forward sale agreements by physical delivery and will not derive the same benefits from the standpoint of improving our credit metrics.

Any impairment of our assets could negatively impact us.

We could experience a reduction in the fair value of our assets, including our investments that we account for under the equity method, upon the occurrence of many of the risks discussed in these risk factors and elsewhere in this report, such as from any inability to operate our existing facilities or develop new projects in Mexico due to recent and proposed changes to laws or regulations or other circumstances affecting the energy sector or our assets in that country, and more generally any loss of permits or approvals that requires us to adjust or cease certain operations and any failure to complete or receive an adequate return on our investments in capital projects. Any such reduction in the fair value of our assets or investments could result in an impairment loss that could materially adversely affect our results of operations for the period in which the charge is recorded. We discuss our impairment testing of long-lived assets and goodwill and the factors considered in such testing in “Part II – Item 7. MD&A – Critical Accounting Estimates” and in Note 1 of the Notes to Consolidated Financial Statements.

The economic interest, voting rights and market value of our outstanding common and preferred stock may be adversely affected by any additional equity securities we may issue.

At February 20, 2024, we had 632,149,916 shares of our common stock and 900,000 shares of our non-convertible series C preferred stock outstanding. Our businesses have substantial capital needs, and we may seek to raise capital by issuing additional equity (as we did in November 2023) or convertible debt securities, which may materially dilute the voting rights and economic interests of holders of our outstanding common and preferred stock and materially adversely affect the trading price of our common and preferred stock.

The dividend requirements of our preferred stock subject us to risks.

Any failure to pay scheduled dividends on our series C preferred stock when due would have a material adverse impact on the market price of our securities and would prohibit us, under the terms of the series C preferred stock, from paying cash dividends on or repurchasing shares of our common stock (subject to limited exceptions) until we have paid all accumulated and unpaid dividends on the series C preferred stock. Additionally, the terms of the series C preferred stock generally provide that if dividends on any shares of the preferred stock have not been declared and paid or have been declared but not paid for three or more semi-annual dividend periods, the holders of the preferred stock would be entitled to elect two additional members to our board of directors, subject to certain terms and limitations.

Our common stock is listed on the Mexican Stock Exchange and registered with the CNBV, which subjects us to additional regulation and liability in Mexico.

In addition to being listed on the NYSE, our common stock is listed on the Mexican Stock Exchange and registered with the CNBV. Such listing and registration subjects us to filing and other requirements in Mexico that have increased our costs and risks of noncompliance. In addition, the CNBV, as the Mexican securities market regulator, has the authority to inspect Sempra’s business, primarily through requests for information and documents; impose fines or penalties on Sempra and its directors and officers for violations of Mexican securities laws and regulations; and seek criminal liability for certain actions conducted or with effects in Mexico. The occurrence of any of these risks could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO ALL SEMPRA BUSINESSES

Operational Risks

Our businesses are subject to risks arising from their infrastructure and systems that support this infrastructure.

Our facilities and the systems that interconnect and/or manage them are subject to risks of, among other things, equipment or process failures due to aging infrastructure or otherwise; human error; shortages of or delays in obtaining equipment, materials, commodities or labor, which have been and may in the future be exacerbated by supply chain constraints or tight labor market conditions, as well as increases to the costs of these items due to inflationary pressures or otherwise, which may not be recoverable in a timely manner or at all; operational restrictions resulting from environmental requirements or governmental interventions; inability to enter into, maintain, extend or replace long-term supply or transportation contracts; and performance below expected levels. Although our businesses undertake capital investment projects to construct, replace, operate, maintain and upgrade facilities and systems, such projects may not be completed or effective at managing these risks and involve significant costs that may not be recoverable. We often rely on third parties, including contractors, to perform work related to these projects and other maintenance activities, which may subject us to liability for safety issues and the quality of work performed by these third parties. Because some of our facilities are interconnected with those of third parties, including third-party natural gas pipelines and power generation facilities that produce most of the power we distribute, the operation of our facilities could also be materially adversely affected by these or similar risks to such third-party systems, which may be unanticipated or uncontrollable by us.

Additional risks associated with our ability to safely and reliably construct, replace, operate, maintain and upgrade facilities and systems, which may be beyond our control, include:

• failure to meet customer demand for electricity and/or natural gas, including electrical blackouts or curtailments or gas outages
• natural gas surges into homes or other properties
• the release of hazardous or toxic substances, including gas leaks
• the failure to respond effectively to catastrophic events

The occurrence of any of these events could affect supply and demand for electricity, natural gas or other forms of energy, cause unplanned outages, damage our assets and/or operations or those of third parties on which our businesses rely, damage property owned by customers or others, and cause personal injury or death. In addition, if we are unable to defend and retain title to the properties we own or obtain or retain rights to construct and operate on the properties we do not own in a timely manner, on reasonable terms or at all, we could lose our rights to occupy and use these properties and the related facilities, which could prevent, limit or delay existing or proposed operations or projects, increase our costs, and result in breaches of permits or contracts and related legal costs, impairments, fines or penalties. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We face risks related to severe weather, natural disasters, physical attacks and other similar events.

Our facilities and infrastructure may be damaged by severe weather, natural disasters, wildfires, accidents, explosions or acts of terrorism, war, or criminality. Because we are in the business of using, storing, transporting and disposing of highly flammable, explosive and radioactive materials and operating highly energized equipment, the risks such incidents pose to our facilities and infrastructure, as well as to the surrounding communities for which we could be liable, are substantially greater than the potential risks to a typical business.

Such incidents could result in operational disruptions, power or gas outages, property damage, personal injury or death and could cause secondary incidents that also may have these or other negative effects, such as fires; leaks of natural gas, natural gas odorant, propane, ethane, other GHG emissions or radioactive material; spills or other damage to natural resources; or other nuisances to affected communities. Any of these occurrences could decrease revenues and earnings and/or increase costs, including maintenance costs or restoration expenses, amounts associated with claims against us, and regulatory fines, penalties and disallowances. In some cases, we may be liable for damages even though we are not at fault, such as when the doctrine of inverse condemnation applies, which we discuss below under “Risks Related to Sempra California – Operational Risks.” For our regulated utilities, these costs may not be recoverable in rates. Insurance coverage for these costs may continue to increase or become prohibitively expensive, be disputed by insurers, or become unavailable for certain of these risks or at adequate levels, and any insurance proceeds may be insufficient to cover our losses or liabilities due to limitations, exclusions, high deductibles, failure to comply with procedural requirements or other factors. Such incidents that do not directly affect our facilities may impact our business partners, supply chains and transportation channels, which could negatively affect our ability to operate. Moreover, weather-related incidents have become more prevalent, unpredictable and severe as a result of climate change or other factors. As a result, these incidents could have a greater impact on our businesses than currently anticipated and, for our regulated utilities, rates may not be adequately or timely adjusted to reflect any such increased impact. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We face evolving cybersecurity risks associated with the energy grid, natural gas pipelines, storage and other infrastructure as well as the collection of personal, sensitive and confidential customer and employee information.

Our use of complex technologies and systems in our operations, including our increasing deployment of new technologies and virtualization of many business activities, and our collection and retention of personal, sensitive and confidential information, represent large-scale opportunities for attacks on or other failures to protect our information systems, information and energy grid and natural gas infrastructure. We are also vulnerable in the event of attacks on or failures to protect third-party vendors’ technologies and systems, depending on the level of access these vendors have to our information and systems. In particular, ransomware and other forms of cyber-attacks targeting utility systems and other energy infrastructure are continuously increasing in sophistication, magnitude and frequency, may not be recognized until launched against a target and may further escalate during periods of heightened geopolitical tensions. Accordingly, we may be unable to anticipate these techniques or to implement adequate security barriers or other preventative measures, making it impossible for us to entirely eliminate this risk.

Additionally, SDG&E and SoCalGas are increasingly required to disclose large amounts of data (including customer personal information and energy use data) to support state initiatives related to grid modernization, customer choice, energy efficiency, demand response and conservation, increasing the risks of inadvertent disclosure or unauthorized access of sensitive information. Moreover, all our businesses operating in California (and in other states and countries that have similar laws) are subject to enhanced state privacy laws, which require companies that collect information about California residents to, among other things, disclose their data collection, use and sharing practices; allow consumers to opt out of certain data sharing with third parties; and assume liability for unauthorized disclosure of certain highly sensitive personal information.

Although we make significant investments in risk management and information security measures for the protection of our systems and data, these measures could be insufficient or otherwise fail. The costs and operational consequences of implementing, maintaining and enhancing these measures are significant and expected to increase to address the growing intensity and complexity of cyber risks. We often rely on third-party vendors to deploy new technologies and maintain and update our systems, and these third parties may not have adequate risk management and information security measures with respect to their systems. Although we have not experienced a material breach of our information systems or data, we and some of our vendors have been and will likely continue to be subject to breaches of and attempts to gain unauthorized access to our systems or data or efforts to otherwise disrupt our operations. Any actual or perceived noncompliance with applicable data privacy and security laws or any incidents targeting our or our vendors’ information systems; the integrity of the energy grid, our pipelines or our distribution, storage and other infrastructure; or our confidential information could result in disruptions to our business operations, regulatory compliance failures, inability to produce accurate and timely financial statements, energy delivery failures, financial and reputational loss, litigation, violations of applicable laws and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Although Sempra currently maintains cyber liability insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover a substantial portion or any of the costs associated with a compromise of our information systems or confidential information, and there is no guarantee that the insurance we currently maintain will continue to be available at rates we believe are reasonable.

We seek growth opportunities in the market organically and inorganically, including through the acquisition of, or partnerships in, operating companies.

We diligently analyze the financial viability of each acquisition, partnership and JV we pursue. However, our diligence may prove to be insufficient and there could be latent or unforeseen defects. In addition, we may not realize all the anticipated benefits from future acquisitions, partnerships or JVs for various reasons, including difficulties integrating operations and personnel to our standards or in a timely manner, higher and unexpected acquisition and operating costs, unknown liabilities, and fluctuations in markets. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Increasing activities and projects intended to advance new energy technologies could introduce us to new risks.

We regularly undertake or become involved in research and development projects and other activities designed to develop new technologies in the energy space, including those related to hydrogen, liquefaction, energy storage, carbon sequestration, grid modernization and others. These activities and projects involve significant employee time, as well as substantial capital resources that may not be recoverable in rates or, with respect to our non-regulated-utility businesses, may not be able to be passed through to customers. We have sought and continue to seek a variety of federal and state funding opportunities for these activities and projects, which can involve significant employee resources and increased compliance requirements with no guarantee that such funding would be received. In addition, the timing to complete these activities and projects is inherently uncertain and may require significantly more time and funding than we initially anticipate. Moreover, many of these technologies are in the early stage of development, and the applicable activities and projects may not be completed or the applicable technologies may not prove economically and technically feasible. If any of these circumstances occurs, we may not receive an adequate or any return on our investment and other resources invested in these activities and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.

The operation of our facilities depends on good labor relations with our employees and our ability to attract and retain qualified personnel.

Several of our businesses have in place collective bargaining agreements with different labor unions, which are generally negotiated on a company-by-company basis. SoCalGas has a collective bargaining agreement that expires on September 30, 2024. Any prolonged negotiation or failure to reach an agreement on these labor contracts as they are up for renewal could result in work stoppages or other labor disruptions. Additionally, we have been faced with a shortage of experienced and qualified personnel in certain specialty operational positions and could experience labor disruptions from personnel in those positions. Any such labor disruption or negotiated wage or benefit increases, whether due to union activities, employee turnover, labor shortages or otherwise, could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Our businesses depend on the performance of counterparties.

Our businesses depend on the performance of business partners, customers, suppliers and other counterparties under contractual and other arrangements to provide, among other things, services, equipment, or commodities and who may have significant unpaid financial obligations to us under these arrangements. If they fail to perform their obligations in accordance with these arrangements, we may be unable to meet our obligations and we may be required to enter into alternative arrangements or honor our underlying commitments at then-current market prices, which may result in losses to us or delays or other disruptions to our operations. Any efforts to enforce the terms of these arrangements through legal or other means could involve significant time and costs and would be unpredictable and subject to failure. In addition, many of these arrangements, including our relationships with the applicable counterparties, are important for the conduct and growth of our businesses. We also may not be able to secure replacement agreements with other counterparties on favorable terms, in a timely manner or at all if any of these arrangements terminate. Further, we often extend credit to customers and other counterparties and, although we perform credit analyses prior to extending credit, we may not be able to collect the amounts owed to us, which could be significant and present an increased risk for our long-term supply, sales and capacity contracts. The failure of any of our counterparties to perform in accordance with their arrangements with us could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

In addition, Sempra Infrastructure’s obligations and those of its counterparties, such as its LNG customers, are contractually subject to suspension or termination for force majeure events, which generally are beyond the control of the parties. Force majeure declarations may also have attendant negative consequences, such as the fees lost by Cameron LNG JV on delivery of excess LNG to tolling customers in connection with certain force majeure events, or loss or deferral of revenue arising from non-deliveries of natural gas from suppliers or LNG to customers in certain circumstances. Also, certain force majeure events may impact the contractors constructing Sempra Infrastructure’s projects, which may result in increased costs or schedule delays. Sempra Infrastructure may have limited remedies available for certain failures to perform, including limitations on damages that may prohibit recovery of costs incurred for any breach of an agreement. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra Infrastructure engages in JVs and invests in companies in which other equity partners may have or share with us control over the applicable project or investment. Sempra Texas also invests in companies it does not control or manage. We discuss the risks related to such arrangements above under “Risks Related to Sempra – Operational and Structural Risks.”

Financial Risks

Our debt service obligations expose us to risks and could require additional equity securities issuances by Sempra or sales of equity interests in subsidiaries or projects under development.

We have significant debt service obligations, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects by, among other things:

• making it more difficult and costly to service, pay or refinance debts as they come due, particularly when interest rates increase or economic or industry conditions are otherwise unfavorable
• limiting flexibility to pursue strategic opportunities or react to business developments or industry changes
• causing lenders to require materially adverse terms for new debt, such as restrictions on uses of proceeds, limitations on incurring additional debt, paying dividends, repurchasing stock, or receiving distributions from subsidiaries or equity method investments and the creation of liens

Sempra’s goal is to maintain or improve its credit ratings, but it may not be able to do so. To maintain these credit ratings, we may seek to reduce our outstanding indebtedness or our need for additional indebtedness by issuing equity securities or selling equity interests in our subsidiaries or development projects. We may not be able to complete any such equity sales on terms we consider acceptable or at all, and any new equity issued by Sempra may dilute the voting rights and economic interests of Sempra’s existing equity holders. Any such outcome could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.

The availability and cost of debt or equity financing could be negatively affected by market and economic conditions and other factors.

Our businesses are capital-intensive, with significant and increasing capital spending expected in future periods. In general, we rely on long-term debt to fund a significant portion of our capital expenditures and repay outstanding debt, and we rely on short-term debt to fund a significant portion of day-to-day operations. Sempra has also raised and may continue to seek capital by issuing equity or selling equity interests in our subsidiaries or investments.

Limitations on the availability of credit, increases in interest rates or credit spreads due to inflation or otherwise or other negative effects on the terms of any financing we pursue could cause us to fund operations and capital expenditures at a higher cost or fail to raise our targeted amount of funds, which could negatively impact our ability to meet contractual and other commitments, progress development projects, make non-safety related capital expenditures and effectively sustain operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

In addition to market and economic conditions, factors that can affect the availability and cost of capital include:

• adverse changes to laws and regulations, including recent and proposed changes to energy market regulation in Mexico
• for Sempra and SDG&E, risks related to California wildfires
• for Sempra, SDG&E and SoCalGas, any deterioration of or uncertainty in the political or regulatory environment for local natural gas distribution companies operating in California
• credit ratings downgrades

Credit rating agencies may downgrade our credit ratings or place them on negative outlook.

Credit rating agencies routinely evaluate Sempra, SDG&E, SoCalGas, SI Partners and certain of our other businesses whose ratings are based on a number of factors, including the factors described below and the ability to generate cash flows; indebtedness levels; overall financial strength; specific transactions or events, such as share repurchases and significant litigation; the status of certain capital projects; and general economic and industry conditions. These credit ratings could be downgraded or subject to other negative rating actions at any time. We discuss these credit ratings in “Part II – Item 7. MD&A – Capital Resources and Liquidity.”

For Sempra, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

• expansion of natural gas liquefaction projects or other unregulated businesses in a manner inconsistent with its present level of credit quality
• the PA LNG Phase 1 project experiences higher construction costs
• Sempra’s consolidated financial measures consistently weaken, or it fails to meet certain financial credit metrics
• catastrophic wildfires caused by SDG&E or by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably earlier than expected
• a ratings downgrade at SDG&E, SoCalGas, Oncor and/or SI Partners

For SDG&E, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

• catastrophic wildfires caused by SDG&E or by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably earlier than expected
• a consistent weakening of SDG&E’s financial metrics, or it fails to meet certain financial credit metrics
• a deterioration in the regulatory environment, including credit negative outcomes of its pending regulatory proceedings
• a ratings downgrade at Sempra

For SoCalGas, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

• SoCalGas’ financial measures consistently weaken, or it fails to meet certain financial credit metrics
• SoCalGas experiences increased business risk due to a deterioration in the regulatory environment, including credit negative outcomes of its pending regulatory proceedings or elevated risk concerning its natural gas utility business
• a ratings downgrade at Sempra

For SI Partners, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:

• SI Partners’ failure to meet certain financial credit metrics
• a deterioration in SI Partners’ business risk profile, including incremental construction risk or adverse changes in the operating environment in Mexico
• the PA LNG Phase 1 project experiences challenges or delays in construction that have an adverse financial impact on SI Partners
• a ratings downgrade at Sempra, IEnova and/or Cameron LNG, LLC

A downgrade of any of our businesses’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, could materially adversely affect the interest rates at which borrowings can be made and debt securities issued and the various fees on our credit facilities. This could make it more costly to borrow money, issue securities and/or raise other types of capital, any of which could reduce our ability to meet our debt obligations and contractual commitments and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We do not fully hedge our assets or contract positions against changes in commodity prices or interest rates, and for positions that are hedged, our hedging mechanisms may not mitigate our risk or reduce our losses as intended.

We use forward contracts, futures, financial swaps and/or options, among other mechanisms, to hedge a portion of our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity in an effort to reduce our, and for SDG&E and SoCalGas, customers’ financial exposure related to commodity price fluctuations. The extent of the coverage to these exposures varies over time. In addition, we have used and may continue to use similar financial instruments to hedge against changes in interest rates. Certain derivative instruments we use to hedge are recorded at fair value through earnings to reflect movements in the price of the derivative, which has recently and could in the future create volatility in our earnings. To the extent we have unhedged positions, or if any hedging counterparty fails to fulfill its contractual obligations or if our hedging strategies do not work as intended, fluctuating commodity prices and interest rates could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Risk management procedures may not prevent or mitigate losses.

Although we have risk management and control systems designed to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended or function as expected. In addition, daily VaR and loss limits, which are primarily based on historic price movements and which we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” may not protect us from losses if prices significantly or persistently deviate from historic prices. As a result of these and other factors, our risk management procedures and systems may not prevent or mitigate losses that could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Market performance or changes in other assumptions could require unplanned contributions to pension and PBOP plans.

Sempra, SDG&E and SoCalGas provide defined benefit pension and PBOP plans to eligible employees and retirees. The cost of providing these benefits is affected by many factors, including the market value of plan assets and the other factors described in Note 9 of the Notes to Consolidated Financial Statements. A decline in the market value of plan assets or an adverse change in any of these other factors could cause a material increase in our funding obligations for these plans, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Legal and Regulatory Risks

We face risks related to failures and delays in obtaining permits, licenses, franchises and other approvals required by our businesses from various governmental agencies.

The industries in which we operate are subject to numerous governmental regulations, and our business requires numerous permits, licenses, rights-of-way, franchises, certificates and other approvals from federal, state, local and foreign governmental agencies. For example, SoCalGas’ franchise agreement with Los Angeles County initially expired in June 2023 and the subsequent extension expired in December 2023. SoCalGas is operating and expects to continue to operate under the terms and provisions of the expired franchise until a new agreement is reached. Additionally, the City of San Diego is studying the feasibility of municipalization as a potential alternative to SDG&E’s existing electric franchise agreement, and various aspects of the natural gas and electric franchise agreements granted by the City of San Diego to SDG&E have also been challenged in two lawsuits that we discuss in Note 16 of the Notes to the Consolidated Financial Statements. These approvals may not be granted in a timely manner or at all or may be modified, rescinded or fail to be extended for a variety of reasons, including due to legal or regulatory changes. Obtaining or maintaining these approvals could result in higher costs or the imposition of conditions or restrictions on our operations. Further, noncompliance by us or certain of our customers with the terms of these approvals could result in their modification, suspension or rescission and subject us to lost revenue, fines and penalties. If any of these approvals are suspended, rescinded or otherwise terminated or modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise impracticable, we may be required to adjust or temporarily or permanently cease certain of our operations, sell the associated assets or remove them from service and/or construct new assets intended to bypass the impacted area, in which case we may lose some of our rate base or revenue-generating assets, our development projects may be negatively affected and we may incur impairment charges or other costs that may not be recoverable. The occurrence of any of these events could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

From time to time, we invest funds in capital projects prior to receiving all regulatory approvals. If there is a delay in obtaining these approvals; if any approval is conditioned on changes or other requirements that increase costs or impose restrictions on our existing or planned operations; if we fail to obtain or maintain these approvals or comply with them or other applicable laws or regulations; if we are involved in litigation that adversely impacts any approval or rights to the applicable property or assets; or if management decides not to proceed with a project, we may be unable to recover any or all amounts invested in that project. Any such occurrence could materially increase our costs, result in material impairments, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Our businesses face climate change concerns and have environmental compliance and clean energy transition and reporting costs.

Climate change and the costs associated with its impacts and mitigation may adversely affect us, including by increasing the costs we incur to transmit energy and provide other services, impacting the demand for and consumption of the energy we transmit and distribute (due to changes in costs, increasingly common severe weather events and other weather patterns, the type of energy transmitted as a result of increasing customer preference for carbon-neutral and renewable sources of energy, and other factors), and affecting the economic health of the regions in which we operate.

Environmental and Climate Change Regulation

We are subject to extensive federal, state, regional, local and foreign statutes, orders, rules and regulations relating to climate change and environmental protection. To comply with these requirements, we must expend significant capital and employee resources on environmental monitoring, surveillance and other measures to track performance; acquisition and installation of pollution control equipment; mitigation efforts; and emissions fees, which could increase as a result of various factors we may not control, including changing laws and regulations, increased enforcement activities, delays in the renewal and issuance of permits, and changes to the mix of energy we transmit and distribute. In addition, we are generally responsible for hazardous substances and other contamination on and the conditions of our projects and properties, regardless of when these conditions arose and whether they are known or unknown. We have been and may be in the future required to pay environmental remediation costs at former facilities and off-site waste disposal sites where any of our businesses is identified as a PRP under federal, state and local environmental laws. For our regulated utilities, some of these costs may not be recoverable in rates. Failure to comply with environmental laws and regulations may subject us to fines and penalties, including criminal penalties in some cases, and/or curtailment of our operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Increasing international, national, regional, state and local environmental concerns and related changes to the legal and regulatory framework, such as requirements for increased monitoring and surveillance, disclosures on environmental performance, pollution monitoring and control equipment, safety practices, emissions fees, taxes, penalties or other obligations or restrictions, may have material negative effects on our operations, costs, corporate planning, and the scope and economics of proposed infrastructure projects or other capital expenditures. Recently enacted California laws requiring expansive disclosures on GHG emissions and other environmental measures, targets and claims subject us to potential liability for these disclosures and could have other consequences that may be difficult to predict, including negative sentiment from current and potential investors, regulators or other groups. Moreover, these new disclosure requirements may use different reporting frameworks and methodologies, including reporting boundaries, which may increase compliance costs and the risk of compliance failures and may create confusion for stakeholders.

In addition, legislation and regulation relating to the control and reduction of GHG emissions and mitigating climate change is proliferating. For example, SB 100 (enacted in 2018) and SB 1020 (enacted in 2022) requires each California electric utility, including SDG&E, to procure at least 50% of its annual electric energy requirements from renewable energy sources by 2026, 60% by 2030, 90% by 2035, and 95% by 2040. State law also requires California’s retail electricity supply to be met with a mix of RPS Program-eligible and zero-carbon resources 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, the Governor of California signed an executive order establishing a new statewide goal to achieve carbon neutrality as soon as possible, and no later than 2045, and achieve and maintain net negative emissions thereafter. The executive order calls on CARB to address this goal in future scoping plans, which affect several major sectors of California’s economy, including transportation, agriculture, development, industrial and others. California has issued new climate initiatives in line with this statewide goal, including two executive orders requiring sales of all passenger vehicles to be zero-emission by 2035. These or other similar new laws and rules may materially restrict our operations, negatively impact demand for our services and/or the energy we transmit and distribute, limit development opportunities, force costly or otherwise burdensome changes to our operations or otherwise materially adversely affect us.

Energy Transition Risks

The energy transition in California and elsewhere, including decarbonization goals, has introduced uncertainty in long-term investor support, leading some to reduce investment in or divest from our sector. Maintaining investor confidence and attracting capital at a competitive cost will depend in part on demonstrating our progress on our action plan supporting Sempra’s aim to have net-zero emissions by 2050 and SDG&E’s and SoCalGas’ aim to have net-zero emissions by 2045. Our ability to achieve these aims depends on many factors, some of which we do not control, including supportive energy laws, policies and regulatory decisions; development and adoption of alternative fuels; successful research and development efforts focused on low-carbon technologies that are economically and technically feasible; cooperation from our partners, financing sources and commercial counterparties; customer participation in conservation and energy efficiency programs, our ability to execute our planned investments in our infrastructure and our customers’ decisions and preferences. Although we have developed interim targets and various plans designed to advance California’s GHG emissions and renewable energy mandates and our own energy goals, we may not be successful.

We will need to continue to expend capital and employee resources to develop and deploy new technologies and modernize grid systems to meet the demand for lower carbon and reliable energy in California and elsewhere and achieve our climate aspirations and those mandated by applicable authorities, which may not be recoverable in rates or, with respect to our non-regulated-utility businesses, may not be able to be passed through to customers. Even if such costs are recoverable, these costs, coupled with necessary safety and reliability investments, may negatively impact the affordability of SDG&E’s and SoCalGas’ customer rates and, for our non-regulated-utility businesses, may cause costs to increase to levels that reduce customer demand and growth. SDG&E and SoCalGas, as well as any of our other businesses affected by GHG emissions mandates, may also be subject to fines and penalties if mandated renewable energy goals are not met, and all our businesses could suffer difficulties attracting investors and business partners, reputational harm and other negative effects if we do not meet or if we scale back our GHG emissions goals or there are negative views about our environmental disclosures or practices generally.

The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We are subject to complex tax and accounting requirements that expose us to risks.

We are subject to complex tax and accounting requirements. These requirements may undergo changes at the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these requirements, including in the event of changes to them or how they are implemented, interpreted or enforced, could increase our operating costs and materially adversely affect how we conduct our business. New tax legislation, regulations or interpretations or changes in tax policies in the U.S., Mexico or other countries in which we operate or do business could negatively affect our tax expense and/or tax balances and our businesses generally. Any failure to comply with these requirements could subject us to fines and penalties, including criminal penalties in some cases. The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We may be negatively impacted by the outcome of litigation or other proceedings in which we are involved.

Our businesses are involved in a number of lawsuits, binding arbitrations, regulatory investigations and other proceedings. We discuss material pending proceedings in Note 16 of the Notes to Consolidated Financial Statements. We have spent, and continue to spend, substantial money, time and employee and management focus on these lawsuits and other proceedings. The uncertainties inherent in lawsuits and other proceedings make it difficult to estimate with any degree of certainty the timing, costs and ranges of costs or outcome of these matters. In addition, juries have demonstrated a willingness to grant large awards, including punitive damages, in response to personal injury, product liability, property damage and other claims. Accordingly, actual costs incurred have and may continue to differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, from insurance or in customer rates. Any of the foregoing could cause reputational damage and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA CALIFORNIA

Operational Risks

Wildfires in California pose risks to Sempra, SDG&E and SoCalGas.

More and Increasingly Severe Wildfires

In recent years, California has experienced some of the largest wildfires (measured by acres burned) in its history. Frequent and severe drought conditions, inconsistent and extreme swings in precipitation, changes in vegetation, unseasonably warm temperatures, low humidity, strong winds and other factors have increased the duration of the wildfire season and the intensity, prevalence and difficulty of prevention and containment of wildfires in California, including in SDG&E’s and SoCalGas’ service territories. Changing weather patterns, including as a result of climate change, could exacerbate these conditions. These wildfires could jeopardize SDG&E’s and SoCalGas’ electric and natural gas infrastructure and third-party property and result in temporary power shortages in SDG&E’s and SoCalGas’ service territories. Certain of California’s local land use policies and forestry management practices have been relaxed to allow for the construction and development of residential and commercial projects in high-risk fire areas, which could lead to increased third-party claims and greater losses related to fires for which SDG&E or SoCalGas may be liable. Any such wildfires in SDG&E’s and SoCalGas’ territories (or outside of these territories in the event the Wildfire Fund is materially diminished) could materially adversely affect SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects, which we discuss further in this risk factor below and above under “Risks Related to All Sempra Businesses – Operational Risks.”

The Wildfire Legislation

In July 2019, the Wildfire Legislation was signed into law, which we discuss in Note 1 of the Notes to Consolidated Financial Statements. The Wildfire Legislation’s legal standard for the recovery of wildfire costs may not be implemented effectively or applied consistently, we may not be eligible for the Wildfire Legislation’s cap on wildfire-related liability if SDG&E fails to maintain a valid annual safety certification from the OEIS or meet other requirements, and/or the Wildfire Fund could be exhausted due to claims against the fund by SDG&E or other participating IOUs as a result of fires in their respective service territories, any of which could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects. PG&E has indicated it will seek reimbursement from the Wildfire Fund for losses associated with the Dixie fire, which burned from July 2021 through October 2021 and was reported to be the largest single wildfire (measured by acres burned) in California history. In addition, the Wildfire Legislation did not change the doctrine of inverse condemnation, which imposes strict liability (meaning that liability is imposed regardless of fault) on a utility whose equipment is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including business interruption losses, interest and attorneys’ fees, even if the utility is not found negligent. In the past, the CPUC has denied recovery of costs incurred as a result of the doctrine of inverse condemnation. The doctrine of inverse condemnation also is not exclusive of other theories of liability, such as negligence, under which additional liabilities, such as fire suppression, clean-up and evacuation costs, medical expenses, and personal injury, punitive and other damages, could be imposed. We are unable to predict the impact of the Wildfire Legislation on SDG&E’s ability to recover costs and expenses if SDG&E’s equipment is determined to be a cause of a fire, and specifically in the context of the application of inverse condemnation.

Cost Recovery Through Insurance or Rates

As a result of California’s doctrine of inverse condemnation, substantial losses recorded by insurance companies, and increased wildfire risk, obtaining insurance coverage for wildfires that could be caused by SDG&E (or, to a lesser extent, SoCalGas) has become increasingly difficult and costly. If these conditions continue or worsen, insurance for wildfire liabilities may become unavailable or may become prohibitively expensive and we may be denied recovery of insurance cost increases through the regulatory process. In addition, insurance for wildfire liabilities may not be sufficient to cover all losses we may incur, or it may not be available to meet the $1.0 billion of primary insurance required by the Wildfire Legislation. We are unable to predict whether we would be able to recover in rates or from the Wildfire Fund the amount of any uninsured losses. A loss that is not fully insured, is not sufficiently covered by the Wildfire Fund and/or cannot be recovered in customer rates could materially adversely affect Sempra’s and one or both of SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.

Wildfire Mitigation Efforts

Although we expend significant resources on measures designed to mitigate wildfire risks, these measures may not be effective in preventing wildfires or reducing our wildfire-related losses and their costs may not be fully recoverable in rates. SDG&E is required by California law to submit wildfire mitigation plans for approval by the OEIS and could be subject to increased risks if these plans are not approved in a timely manner or the measures set forth in the plans are not implemented effectively, as well as fines or penalties for any failure to comply with the approved plans. One of our wildfire mitigation strategies is to de-energize certain circuits for safety when there is elevated weather-related wildfire ignition risk. These “public safety power shutoffs” have been subject to scrutiny by various stakeholders, including customers, regulators and lawmakers, which could increase the risk of liability for damages associated with these events. Such costs may not be recoverable in rates. Unrecoverable costs, adverse legislation or rulemaking, scrutiny by key stakeholders, ineffective wildfire mitigation measures or other negative effects associated with these efforts could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.

The electricity industry is undergoing significant change, including increased deployment of DER, technological advancements, evolving procurement service standards, and political and regulatory developments.

Electric utilities in California are experiencing increasing deployment of DER, such as solar generation, energy storage and energy efficiency and demand management technologies, and California’s environmental policy objectives are accelerating the pace and scope of these changes. This growth of DER will require further modernization of the electric grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, attaining California’s clean energy goals will require sustained investments in transmission and distribution grid modernization, renewable integration projects, energy efficiency programs, operational and data management systems, and electric vehicle and energy storage infrastructure. The growth of third-party energy storage alternatives and other technologies also may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers. Certain FERC transmission development projects are open to competition, allowing independent developers to compete with incumbent utilities for the construction and operation of transmission facilities. The CPUC is conducting various proceedings regarding DER, including the evaluation of special programs and pilots; changes to the planning and operation of the electric grid to prepare for higher penetration of DER; future grid modernization investments; the deferral of traditional grid investments by DER; and the role of the electric grid operator. These proceedings and the broader changes in California’s electricity industry could result in new regulations, policies and/or operational changes that could materially adversely affect SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Most of SDG&E’s customers receive electric procurement service from a load-serving entity other than SDG&E through programs such as CCA and DA. CCA is only available if a customer’s local jurisdiction (city or county) offers such a program, as is the case with the City of San Diego and certain other jurisdictions in SDG&E’s service territory, and DA is currently limited by a cap based on gigawatt hours. As a result of customers electing CCA and DA services, 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 purpose of the framework is to help ensure SDG&E’s procurement cost obligations are more equitably shared among customers served by SDG&E and customers now served by CCA and DA. If the framework or other mechanisms designed to achieve ratepayer indifference do not perform as intended, if the law changes, or if the law is not interpreted or enforced as expected, SDG&E’s remaining bundled customers could experience large increases in rates for commodity costs under commitments made on behalf of CCA and DA customers prior to their departure or, if all such costs are not recoverable in rates, SDG&E could experience material increases in its unrecoverable commodity costs. Any of these outcomes could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Natural gas has increasingly been the subject of political and public debate, including a desire by some to eventually reduce or eliminate reliance on natural gas as an energy source.

Certain California legislators and other stakeholders have expressed a desire to limit or eliminate reliance on natural gas as an energy source by advocating increased use of renewable electricity and electrification. Reducing methane emissions also has become a major focus of certain local, state and federal agencies, resulting in passed or proposed legislation, regulation, policies and ordinances to prohibit or restrict the use of natural gas in new buildings, appliances and other applications. These actions could have the effect of reducing natural gas use over time.

CARB, California’s primary regulator for GHG emissions reduction programs, has proposed to reduce natural gas demand through building decarbonization measures (such as zero-emission standards for space and water heaters) or legislation requiring increased renewable electricity generation. Additionally, the CEC’s Title 24 requirements mandate that new construction include electric-ready buildings and heat pump technologies beginning in 2023.

The CPUC has an ongoing proceeding that seeks to establish a state-wide process to help utilities plan appropriate gas infrastructure portfolios as natural gas usage in the state is expected to change with overall consumption expected to decline. This includes a General Order requiring site-specific approvals for certain gas infrastructure projects. The CPUC may continue to enact measures to reduce natural gas demand (such as more aggressive energy efficiency programs), promote fuel substitution (such as replacement of natural gas appliances with electric appliances), and order other changes (such as its decision to eliminate gas line extension allowances for new applications submitted on or after July 1, 2023).

A substantial reduction in or the elimination of natural gas use in California without adequate recovery of investments could result in impairment of some or all of SoCalGas’ and SDG&E’s natural gas infrastructure assets if they were not permitted to be repurposed for alternative fuels, were required to be depreciated on an accelerated basis or were to become stranded, which could have a material adverse effect on SoCalGas’, SDG&E’s and Sempra’s results of operations, financial conditions, cash flows and/or prospects.

SDG&E may incur significant costs and liabilities from its partial ownership of a nuclear facility being decommissioned.

SDG&E has a 20% ownership interest in SONGS, which we discuss in Note 15 of the Notes to Consolidated Financial Statements. SDG&E and each of the other owners of SONGS is responsible for financing its share of the facility’s expenses and capital expenditures, including those related to decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to risks, including:

• the potential release of radioactive material
• the potential harmful effects from the former operation of the facility
• limitations on the insurance commercially available to cover losses associated with operating and decommissioning the facility
• uncertainties with respect to the technological and financial aspects of decommissioning the facility

SDG&E maintains the SONGS NDT to provide funds for nuclear decommissioning. Trust assets generally have been invested in equity and debt securities, which are subject to market fluctuations. A decline in the market value of trust assets, an adverse change in the law regarding funding requirements for decommissioning trusts, or changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment due to inflationary pressures or otherwise could increase the funding requirements for these trusts, which costs may not be fully recoverable in rates. In addition, CPUC approval is required to make withdrawals from the NDT, and CPUC approval for certain expenditures may be denied if the CPUC determines the expenditures are unreasonable. In addition, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the NDT. Rate recovery for overruns would require CPUC approval, which may not occur.

The occurrence of any of these events could result in a reduction in our expected recovery and have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Legal and Regulatory Risks

SDG&E and SoCalGas are subject to extensive regulation.

Rates and Other Financial Matters

The CPUC regulates SDG&E’s and SoCalGas’ customer rates, except for SDG&E’s electric transmission rates that are regulated by the FERC, and conditions of service. The CPUC also regulates SDG&E’s and SoCalGas’ sales of securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters in various ratemaking proceedings. The CPUC periodically approves SDG&E’s and SoCalGas’ customer rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments while incorporating a risk-based decision-making framework, as well as certain settlements with third parties. The outcome of ratemaking proceedings can be affected by various factors, many of which are not in our control, including the level of opposition by intervening parties; any rejection by the CPUC of settlements with third parties; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of regulators, customers and other stakeholders. These ratemaking proceedings include decisions about major programs in which SDG&E and SoCalGas make investments under an approved CPUC framework, such as wildfire mitigation and pipeline and storage integrity and safety enhancement programs, but which investments may remain subject to a CPUC filing or reasonableness review based on potentially unclear standards or other factors as described above that may result in the disallowance of incurred costs. SDG&E and SoCalGas also may be required to make investments and incur other costs to comply with proposed legislative and regulatory requirements and initiatives, including those related to California’s climate goals and policies, and the ability to recover these costs and investments may depend on the final form of the legislative or regulatory requirements and the corresponding ratemaking mechanisms. Recovery may be delayed and/or insufficient if the applicable ratemaking mechanism involves a significant time lag between when costs are incurred and when those costs are recovered in rates or if there are material differences between the authorized costs embedded in rates (which are set on a prospective basis) and the actual costs incurred. Delays may also result from the administrative process, or the CPUC may deny recovery altogether on the basis that costs were not reasonably or prudently incurred or for other reasons, such as customer affordability. Even if recoverable, investing to support the regulatory requirements and demand for lower carbon, reliable energy in California and in necessary safety and reliability at the same time may negatively impact the affordability of SDG&E’s and SoCalGas’ customer rates and their and Sempra’s results of operations, financial condition, cash flows and/or prospects.

In addition, a CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and return on rate base, and the CCM applies in the interim years and considers changes in the cost of capital based on changes in interest rates for each 12-month period ending September 30 (the measurement period), subject to regulatory approval. 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 as a whole. Any such rate change due to a downward trigger of the CCM or the denial by the CPUC of an automatic upward trigger of the CCM could have a material adverse effect on Sempra’s and the applicable utility’s results of operations, financial condition, cash flows and/or prospects. We discuss the CCM in “Part I – Item 1. Business - Ratemaking Mechanisms – Sempra California – Cost of Capital Proceedings,” and in Note 4 of the Notes to Consolidated Financial Statements.

The FERC regulates electric transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the rates of return on investments in electric transmission assets, and other similar matters involving

SDG&E. These ratemaking mechanisms are subject to many risks similar to those described above regarding the CPUC ratemaking proceedings.

CPUC Authority Over Operational Matters

Our operations are subject to CPUC rules (and similar FERC rules), commonly referred to as “affiliate rules,” relating to transactions among SDG&E, SoCalGas and other Sempra businesses. These rules primarily impact market transactions and marketing activities involving transmission supply and capacity, including sales or other trades of natural gas or electricity between or among SDG&E and SoCalGas and Sempra and its covered affiliates. These rules, as well as any changes to these rules or their interpretations or additional more restrictive CPUC or FERC rules related to transactions with affiliates, could materially adversely affect our operations and, in turn, our results of operations, financial condition, cash flows and/or prospects.

Additionally, the CPUC has regulatory authority related to safety standards and practices, reliability and planning, competitive conditions and a wide range of other operational matters, including citation and enforcement programs concerning matters such as safety activity, disconnection and billing practices, resource adequacy and environmental compliance. Many of these standards and citation and enforcement programs are becoming more stringent and could subject a utility to significant penalties and fines, as well as higher operating costs. The CPUC conducts reviews and audits of the matters under its authority and may launch investigations or open proceedings at its discretion, the results of which could include citations, disallowances, fines and penalties, as well as corrective or mitigation actions to address any noncompliance, any of which may not be sufficiently funded by customer rates or at all. Any such occurrence could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

We discuss various CPUC proceedings relating to SDG&E and SoCalGas in Notes 4 and 16 of the Notes to Consolidated Financial Statements.

Regulatory Changes and Influence of Other Organizations

SDG&E, SoCalGas and Sempra may be materially adversely affected by revisions or reinterpretations of existing or new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies, any of which could change how SDG&E and SoCalGas operate, affect their ability to recover various costs through rates or adjustment mechanisms, require them to incur additional expenses or otherwise materially adversely affect their and Sempra’s results of operations, financial condition, cash flows and/or prospects.

SDG&E and SoCalGas are also affected by numerous advocacy groups, including California Public Advocates Office, The Utility Reform Network, Utility Consumers’ Action Network and the Sierra Club. Any success by any of these groups in directly or indirectly influencing legislators and regulators could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

SoCalGas has incurred and may continue to incur significant costs, expenses and other liabilities related to the Leak.

From October 23, 2015 through February 11, 2016, SoCalGas experienced the Leak, which we describe in Note 16 of the Notes to Consolidated Financial Statements.

Litigation

In September 2021, SoCalGas and Sempra entered into an agreement with counsel to resolve approximately 390 lawsuits including approximately 36,000 plaintiffs (the Individual Plaintiffs) then pending against SoCalGas and Sempra related to the Leak for a payment of up to $1.8 billion. Over 99% of the Individual Plaintiffs participated and submitted valid releases, and SoCalGas paid $1.79 billion in 2022 under the agreement. The Individual Plaintiffs who did not participate in the settlement (the Non-Settling Individual Plaintiffs) are able to continue to pursue their claims. As of February 20, 2024, there are approximately 100 Non-Settling Individual Plaintiffs remaining. In addition, as of February 20, 2024, new lawsuits related to the Leak on behalf of approximately 413 new plaintiffs have been filed against SoCalGas and Sempra since the September 2021 settlement. This litigation seeks compensatory and punitive damages, property damage and diminution in property value, injunctive relief and civil penalties. Additional litigation may be filed against us related to the Leak or our responses to it. The costs of defending against, settling or otherwise resolving the pending lawsuits or any new litigation could materially adversely affect SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects. We discuss the risks associated with litigation above under “Risks Related to All Sempra Businesses – Legal and Regulatory Risks” and in this risk factor below under “Accounting and Other Impacts.”

Natural Gas Storage Operations and Reliability

In February 2017, the CPUC opened proceeding SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including analyzing alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated.

If the Aliso Canyon natural gas storage facility were to be permanently closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we may record an impairment of the facility, which could be material, incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized. Any such outcome could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Accounting and Other Impacts

At December 31, 2023, $31 million is accrued in Reserve for Aliso Canyon Costs and $2 million is accrued in Deferred Credits and Other on SoCalGas’ and Sempra’s Consolidated Balance Sheets. These accruals do not include any amounts in excess of what has been reasonably estimated to resolve certain matters that we describe in “Litigation” above, nor any amounts that may be necessary to resolve threatened litigation, other potential litigation or other costs. We are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued, which could be significant and could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Any failure by the CPUC to adequately reform SDG&E’s electric rate structure could negatively impact SDG&E and Sempra.

The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation (primarily solar installations) for residential and business customers. Depending on when the on-site generation is installed, NEM customers receive a full retail rate or a reduced retail rate for energy they generate but do not use that is fed to the utility’s power grid, which results in these customers not paying their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain exceptions, but still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. As more and higher electric-use customers switch to NEM and self-generate energy, the burden on remaining non-NEM customers, who effectively subsidize the unpaid NEM costs, increases, which in turn encourages more self-generation and further increases rate pressure on remaining non-NEM customers.

The current electric residential rate structure in California is primarily based on consumption volume, which places a higher rate burden on customers with higher electric use while subsidizing lower-use customers. In December 2023, a new Net Billing Tariff was implemented for customers who interconnect their qualifying on-site renewable generation after April 2023. The new Net Billing Tariff revised the NEM structure for new customers with a retail export compensation rate that is better aligned with the value provided to the grid by behind-the-meter energy generation systems and retail import rates that encourage electrification and adoption of solar systems paired with storage. The new Net Billing Tariff is designed to compensate customers for the value of their exports to the grid based on avoided cost. Additionally, in response to California legislation adopted in 2022, the CPUC has initiated a rulemaking to broadly restructure the way fixed costs are collected, moving away from volumetric only charges and incorporating an income-graduated fixed charge for default residential rates. The intent of such a fixed charge is to establish a rate structure that allows the utility to collect a greater portion of its fixed costs on a non-volumetric basis, achieve the state’s climate goals through end-use electrification and provide a more affordable rate design on average for lower-income customers. We expect a CPUC decision adopting the fixed charge by July 2024 with implementation occurring as early as the second half of 2025. Depending on the effectiveness of the new Net Billing Tariff and fixed charge, which are uncertain, the risks associated with the existing NEM tariff and rate design could continue or increase.

SDG&E believes the establishment of a charge independent of consumption volume for residential customers is critical to help distribute rates among all customers that rely on the electric transmission and distribution system, including those participating in the NEM program. The absence of a charge independent of consumption volume coupled with the continuing increase of solar installation and other forms of self-generation and DER, as well as energy efficiency initiatives that could also reduce delivered volumes, could adversely impact electricity rates and the reliability of the electric transmission and distribution system. Any such impact could subject SDG&E to increased customer dissatisfaction, increased likelihood of noncompliance with CPUC or other safety or operational standards and increased risks attendant to any such noncompliance, as we discuss above, as well as increased costs, including power procurement, operating and capital costs, and potential disallowance of recovery for these costs.

If the CPUC does not adequately reform SDG&E’s residential rate structure to better achieve reasonable, cost-based electric rates that are competitive with alternative sources of power and adequate to maintain the reliability of the electric transmission and distribution system, such failure could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA TEXAS UTILITIES

Operational and Structural Risks

Certain ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, operations and policies of Oncor.

Various “ring-fencing” measures, governance mechanisms and commitments are in place that create legal and financial separation between Oncor Holdings, Oncor and their subsidiaries, on the one hand, and Sempra and its affiliates and subsidiaries, on the other hand. These measures are designed to enhance Oncor’s separateness from its owners and mitigate the risk that Oncor would be negatively impacted by a bankruptcy or other adverse financial development affecting its owners. These measures subject us and Oncor to various restrictions, including:

• seven members of Oncor’s 13-person board of directors must be independent directors in all material respects under the rules of the NYSE in relation to Sempra and its affiliates and any other owners of Oncor, and also must have no material relationship with Sempra or its affiliates or any other owners of Oncor currently or within the previous 10 years; of the six remaining directors, two must be designated by Sempra, two must be designated by Oncor’s minority owner, TTI, and two must be current or former Oncor officers
• Oncor will not pay dividends or other distributions (except for contractual tax payments) if (i) a majority of Oncor’s independent directors or any of the directors appointed by TTI determines that it is in the best interest of Oncor to retain such amounts to meet expected future requirements, (ii) the payment would cause Oncor’s debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT, or (iii) unless otherwise allowed by the PUCT, Oncor’s senior secured debt credit rating by any of the Rating Agencies falls below BBB (or Baa2 for Moody’s)
• there must be certain “separateness measures” maintained to reinforce the legal and financial separation of Oncor from Sempra, including a requirement that dealings between Oncor and Sempra or Sempra’s affiliates (other than Oncor Holdings and its subsidiaries) must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or membership interests for any entity other than Oncor
• a majority of Oncor’s independent directors and the directors designated by TTI that are present and voting (with at least one required to be present and voting) must approve any annual or multi-year budget if the aggregate amount of capital expenditures or O&M in the budget differs by more than 10% from the corresponding amounts in the budget for the preceding fiscal year or multi-year period, as applicable

As a result of these measures, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, operations and policies of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends or other distributions, strategic planning and other important matters. Moreover, all directors of Oncor, including the directors we have appointed, have considerable autonomy and have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may in some cases be contrary to our interests. To the extent the directors approve or Oncor otherwise pursues actions that are not in our interest, our results of operations, financial condition, cash flows and/or prospects may be materially adversely affected.

Industry-Related Risks

Changes in the regulation of Oncor or the regulation or operation of the electric utility industry and/or the ERCOT market could negatively affect Oncor.

Oncor operates in the electric utility industry and, as a result, it is subject to many of the same or similar risks as Sempra California as we describe above under “Risks Related to Sempra California,” particularly with respect to regulation by federal, state, and local legislative and regulatory authorities regarding rates and other financial matters as well as operational matters. Oncor operates in the ERCOT market. In ERCOT, rates are set by the PUCT based on a historical test year, and as a result, the rates Oncor is allowed to charge generally will not exactly match its costs at any given point in time and there is no assurance that it will be able to timely or fully recover its actual costs and/or earn its full return on invested capital. Further, the approved levels of recovery could be significantly less than the requested levels, and the approved timing for recovery could differ from proposed timelines. In addition to requests to recover its costs, Oncor’s rate proceedings may contain other requests. Failure to receive approval of its requests in any rate proceeding could adversely impact Oncor, which could adversely impact us, and those impacts could be material.

The costs and burdens associated with complying with the various legislative and regulatory requirements to which Oncor is subject at the federal, state, and local levels and adjusting Oncor’s business and operations in response to legislative and regulatory developments, including changes in ERCOT, and any fines or penalties that could result from any noncompliance, may have a material adverse effect on Oncor. In addition, insufficient electric capacity within ERCOT or significant changes within ERCOT or to the ERCOT market structure that impact transmission and distribution utilities, including additional regulatory requirements or oversight, could materially adversely affect Oncor. Moreover, legislative, regulatory, market or industry activities could adversely impact Oncor’s collections and cash flows and jeopardize the predictability of utility earnings. For instance, the PUCT has instituted various projects reviewing the regulatory framework regarding DER and other non-traditional technologies. As DER usage continues to grow, related regulatory decisions, including with respect to ERCOT market rules and transmission and distribution utilities’ ability to invest in non-traditional electricity delivery solutions, could adversely impact Oncor’s revenues and operations. If Oncor does not successfully respond to applicable legislative, regulatory, market or industry developments, Oncor could suffer a deterioration in its results of operations, financial condition, cash flows and/or prospects, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Financial Risks

Oncor could have liquidity needs that necessitate additional investments.

Oncor’s business is capital-intensive, with significant and increasing capital spending expected in future periods, and it relies on external financing as a significant source of liquidity for its capital requirements. In the past, Oncor has financed much of its cash needs from operations and with proceeds from indebtedness, but these sources of capital may not be adequate or available at reasonable prices or on other reasonable terms in the future. Because our commitments to the PUCT prohibit us from making loans to Oncor, we may elect to make capital contributions to Oncor if it fails to meet its capital requirements or is unable to access sufficient capital from other sources to finance its ongoing needs. Any such investments could be substantial, would reduce the cash available to us for other purposes, may not be recovered, and could increase our indebtedness, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Sempra could incur substantial tax liabilities if EFH’s 2016 spin-off of Vistra is deemed to be taxable.

As part of its ongoing bankruptcy proceedings, in 2016, EFH distributed all the outstanding shares of common stock of its subsidiary Vistra Energy Corp. (formerly TCEH Corp. and referred to herein as Vistra) to certain creditors of TCEH LLC (the spin-off), and Vistra became an independent, publicly traded company. Vistra’s spin-off from EFH was intended to qualify for partially tax-free treatment to EFH and its shareholders under Sections 368(a)(1)(G), 355 and 356 of the U.S. Internal Revenue Code of 1986 (as amended) (collectively referred to as the Intended Tax Treatment). In connection with and as a condition to the spin-off, EFH received a private letter ruling from the IRS regarding certain issues relating to the Intended Tax Treatment, as well as tax opinions from counsel to EFH and Vistra regarding certain aspects of the spin-off not covered by the private letter ruling.

In connection with the signing and closing of the merger of EFH with an indirect subsidiary of Sempra (the Merger), EFH sought and received a supplemental private letter ruling from the IRS and Sempra and EFH received tax opinions from their respective counsels that generally provide that the Merger will not affect the conclusions reached in, respectively, the IRS private letter ruling and tax opinions issued with respect to the spin-off described above. Similar to the IRS private letter ruling and opinions issued with respect to the spin-off, the supplemental private letter ruling is generally binding on the IRS and any opinions issued with respect to the Merger are based on factual representations and assumptions, as well as certain undertakings, made by Sempra and EFH. If such representations and assumptions are untrue or incomplete, any such undertakings are not complied with, or the facts upon which the IRS supplemental private letter ruling or tax opinions (which will not impact the IRS position on the transactions) are based are different from the actual facts relating to the Merger, the tax opinions and/or supplemental private letter ruling may not be valid and could be challenged by the IRS. Even though Sempra Texas Holdings Corp. would have administrative appeal rights if the IRS were to invalidate its private letter ruling and/or supplemental private letter ruling, including the right to challenge any adverse IRS position in court, any such appeal would be subject to uncertainties and could fail. If it is ultimately determined that the Merger caused the spin-off not to qualify for the Intended Tax Treatment, Sempra, through its ownership of Sempra Texas Holdings Corp., could incur substantial tax liabilities, which would materially reduce the value associated with our indirect investment in Oncor and could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

RISKS RELATED TO SEMPRA INFRASTRUCTURE

Operational Risks

Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels.

Energy Infrastructure Projects

We are involved in a number of energy infrastructure projects in various stages of development and construction, which subject us to numerous risks. Success in developing each project depends on, among other things:

• our financial condition and cash flows and other factors that impact our ability to invest sufficient funds in the project, including for preliminary activities conducted before we determine whether the project is feasible or economically attractive
• project assessment and design and our ability to foresee and incorporate new and developing trends and technologies in the energy industry, such as our pursuit of projects and design solutions to help enable our and our customers’ climate goals
• our ability to reach a final investment decision or meet other milestones, which may be influenced by external factors outside our control, including the global economy and energy and financial markets, actions by regulators, achieving necessary internal and external approvals, and many of the other factors described in this risk factor
• negotiation of satisfactory EPC agreements and renegotiation in the event of delays in final investment decisions or failures to meet other specified deadlines
• identification of suitable partners, customers, suppliers and other necessary counterparties
• progressing relationships from MOUs, HOAs or similar arrangements, which are non-binding, to execution of binding, definitive agreements and participation in the project
• negotiation and maintenance of satisfactory equity, purchase, sale, supply, transportation and other appropriate commercial agreements, and satisfaction of any conditions to effectiveness of such agreements, including reaching a positive final investment decision within agreed timelines
• timely receipt and maintenance of required governmental permits, licenses and other authorizations under terms we find reasonable
• our project partners’, contractors’, equipment providers’ and other vendors’ and counterparties’ willingness and financial or other ability to make their required investments or fulfill their contractual commitments on a timely basis
• timely, satisfactory and on-budget completion of construction, which could be negatively affected by engineering problems, work stoppages, unavailability or increased costs of materials, equipment, labor and commodities due to inflation or supply chain or other issues, and a variety of other factors, many of which we discuss above under “Risks Related to All Sempra Businesses – Operational Risks” and elsewhere in this risk factor
• implementation of new or changes to existing laws or regulations that impact our infrastructure or the energy sector generally
• obtaining satisfactory financing for the project, particularly when inflation and interest rates are rising
• the absence of hidden defects on or inherited environmental liabilities for the site of the project
• fast and cost-effective resolution of any litigation or unsettled property rights affecting the project
• geopolitical events and other uncertainties

Any failures with respect to the above factors or other factors material to any particular project could involve additional costs, otherwise negatively affect our ability to successfully complete the project and force us to impair or write off amounts we have invested in the project. If we are unable to complete a development project, if we experience delays, or if construction, financing or other project costs exceed our estimated budgets and we are required to make additional capital contributions, we may not receive an adequate or any return on our investment and other resources expended on the project and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.

The operation of existing facilities and any future projects we complete involves many risks, including the potential for unforeseen design flaws, engineering challenges, or the breakdown for other reasons of facilities, equipment or processes; labor disputes; fuel interruption; environmental contamination; increasing regulatory requirements, including from regulations aiming to reduce GHG emissions; and the other operational risks that we discuss above under “Risks Related to All Sempra Businesses – Operational Risks.” Any of these events could lead to our facilities being idle for an extended period of time or operating below expected levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

LNG Export Projects

In addition to the risks described above that are applicable to all our energy infrastructure projects, we are exposed to additional risks in connection with our LNG export projects, including the ECA LNG Phase 1 project and PA LNG Phase 1 project under construction and our potential development of additional LNG export facilities. We discuss our LNG export projects in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.” Each of these projects faces numerous risks. Our ability to reach a final investment decision for each project and, if a positive decision is made and a project is completed, the overall success of the project depend in part on global energy markets. In general, depressed natural gas and LNG prices in the markets we intend to serve could reduce the pricing and cost advantages of exporting domestically produced natural gas and LNG, which could lead to decreased demand. In addition, global oil prices and their associated current and forward projections could reduce demand for natural gas and LNG in some sectors. Although demand for natural gas is currently strong due to increased recognition of the importance of energy security and climate aims, a reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, reduced economic activity in general, or as a result of calls by some to limit or eliminate global reliance on natural gas. Both the U.S. and Mexico will hold federal elections in 2024 and LNG exports face increased political scrutiny in connection with these elections. Moreover, because LNG projects take a number of years to develop and construct, it is difficult to match current and expected demand with the projected supply from projects under development. Additionally, shifts in U.S. and foreign energy policy could impact supply, demand and other matters critical to LNG projects, such as permitting and other approval processes. The current Administration has temporarily paused LNG export approvals while the DOE reviews the economic and environmental analyses it uses to evaluate LNG export applications to non-FTA countries, and the DOE has recently implemented changes to its approach to requests for extensions of time to commence LNG exports under existing non-FTA approvals. These actions, as well as other market factors such as oil prices, could delay or hamper the development of U.S. LNG export facilities and make LNG projects in other parts of the world more feasible and competitive with LNG projects in North America, thus increasing supply and competition for global LNG demand. Any of these occurrences could impact competition and prospects for developing LNG export projects and negatively affect the performance and prospects of any of our projects that are or become operational.

Our projects may face distinct disadvantages relative to some LNG projects being pursued by other project developers, including:

• The proposed Cameron LNG Phase 2 project is subject to certain restrictions and conditions under the financing agreements for the Cameron LNG Phase 1 facility and requires unanimous consent of all JV members, including with respect to the equity investment obligations of each partner. We may not be able to satisfy the conditions under the financing agreements, receive members’ consent or obtain the extension of our non-FTA approval, in which case our ability to develop the Cameron LNG Phase 2 project would be jeopardized.
• The ECA LNG projects under construction and in development are subject to ongoing land and permit disputes that could obstruct efforts to find or maintain suitable partners, customers and financing arrangements and hinder or halt construction and, if the projects are completed, operations. We discuss these risks below and under “Risks Related to Sempra Infrastructure – Legal and Regulatory Risks.” In addition, the Mexican regulatory process and overlay of U.S. regulation for natural gas exports to LNG facilities in Mexico are not well developed, which, among other factors, contributed to delays in obtaining a necessary permit from the Mexican government for the ECA LNG Phase 1 project and could cause similar delays or other hurdles in the future and lead to difficulties finding or maintaining suitable partners, customers and financing arrangements. Further, while we do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility, we expect construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has long-term regasification contracts for 100% of the regasification facility’s capacity through 2028. This makes the decisions on whether, when and how to pursue the proposed ECA LNG Phase 2 project dependent in part on whether the investment in this project would, over the long term, be more beneficial financially than continuing to supply regasification services under our existing contracts. In addition, the Baja California region does not have extensive sources of natural gas, and our development opportunities in Mexico, including the proposed ECA LNG Phase 2 project, would require significant upgrades in natural gas transportation infrastructure that would be costly and time-consuming.
• The PA LNG Phase 1 project under construction and the PA LNG Phase 2 project in development are located at a greenfield site and therefore are subject to disadvantages relative to projects being constructed or developed at brownfield sites, including increased time and costs to develop and construct the projects. Additionally, in February 2020, Sempra Infrastructure filed an application with the DOE to permit LNG produced from the proposed PA LNG Phase 2 project to be exported to all current and future FTA and non-FTA countries. We do not expect the DOE to act on this application until after the conclusion of the temporary pause on the DOE’s LNG export approvals.

Development of these or any other LNG export projects will depend on the expansion of our existing pipeline interconnections or the ability to permit and construct new pipeline facilities, each of which may require us to enter into additional pipeline interconnection agreements with third-party pipelines, which may not be possible on commercially reasonable terms or at all.

The capital requirements for our LNG export projects can be significant, even if we ultimately decide not to make a positive final investment decision. In addition, our proposed facilities may not be completed in accordance with estimated timelines or budgets or at all as a result of the above or other factors, and delays, cost overruns or our inability to complete one or more of these projects could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Financing Arrangements

We are and may continue to become involved in various financing arrangements with respect to our energy infrastructure projects, including guarantees, indemnities and loans. These arrangements could expose us to additional risks, including exposure to losses upon the occurrence of certain events related to the development, construction, operation or financing of the applicable projects, which could have a material adverse effect on our future results of operations, financial condition, cash flows and/or prospects.

Fixed-price long-term contracts for services or commodities expose our businesses to inflationary pressures.

Sempra Infrastructure seeks to secure long-term contracts for services and commodities in an effort to optimize the use of its facilities, reduce volatility in earnings and support the construction of new infrastructure. Certain of these contracts are at fixed prices, and their profitability may be negatively affected by inflationary pressures, including increased labor, materials, equipment, commodities and other operational costs, rising interest rates that affect financing costs and changes in applicable exchange rates. We try to mitigate these risks by, among other things, using variable pricing tied to market indices, anticipating and providing for cost escalation when bidding on projects, contracting for direct pass-through of operating costs and/or entering into hedges. However, these measures may not fully or substantially offset any increases in operating expenses or financing costs caused by inflationary pressures and their use could introduce additional risks, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We face risks from increased competition.

The markets in which we operate are characterized by numerous capable competitors, many of which have extensive and diversified development and/or operating experience domestically and internationally and financial resources similar to or greater than ours. In particular, the natural gas pipeline, storage and LNG market segments recently have been characterized by strong and increasing competition for winning new development projects and acquiring existing assets. These competitive factors could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

We may not be able to enter into, maintain, extend or replace long-term supply, sales or capacity agreements.

The ECA Regas Facility has long-term capacity agreements with a limited number of counterparties, and also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified for sale to other parties. In addition, Cameron LNG JV has long-term liquefaction and regasification tolling agreements with three counterparties that collectively subscribe for the full nameplate capacity of the Cameron LNG Phase 1 facility, and long-term sale and purchase agreements are in place for the expected capacity at the ECA LNG Phase 1 and PA LNG Phase 1 projects under construction. The long-term nature of these agreements and the small number of customers at each of these facilities exposes us to risks, including increased risk if these counterparties fail to meet their contractual obligations on a timely basis, increased credit risks, and risks associated with our relationships with these counterparties, including increased impacts of disputes or other similar issues which we have experienced in the past. Any such issues that arise in the future with respect to our long-term contracts could lead to significant legal and other costs, result in cancelation of certain key contracts or otherwise adversely affect our relationships with long-term customers, suppliers or partners, and could negatively impact the reliability of revenues from the applicable projects and the prospects for any implicated development projects. Any such event could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra Infrastructure’s ability to enter into new or replace existing long-term capacity agreements for its natural gas pipeline operations depends on, among other factors, demand for and supply of LNG and/or natural gas from its transportation customers, which may include our LNG export facilities. A decrease in demand for or supply of LNG or natural gas from such customers or the occurrence of other events that hinder Sempra Infrastructure from maintaining such agreements or establishing new ones could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

The electric generation and wholesale power sales industries are highly competitive. As more plants are built, supplies of energy and related products may exceed demand, competitive pressures may increase and wholesale electricity prices may decline or become more volatile. Without long-term power sales agreements, our revenues may be subject to increased volatility, and we may be unable to sell the power that Sempra Infrastructure’s facilities are capable of producing at favorable prices or at all, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We rely on transportation assets and services, much of which we do not own or control, to deliver natural gas and electricity.

We depend on electric transmission lines, natural gas pipelines and other transportation facilities and services owned and operated by third parties to, among other things:

• deliver the natural gas, LNG, electricity and LPG we sell to customers or use for our LNG export facilities
• supply natural gas to our gas storage and electric generation facilities
• provide retail energy services to customers

If transportation is disrupted, the construction of necessary interconnecting infrastructure is not completed on schedule or at all or capacity is inadequate, we may be delayed in completing projects under development and/or unable to meet our contractual obligations to customers of those projects or existing projects, in which case we may be responsible for damages they incur, such as the cost of acquiring alternative supplies at then-current spot market rates, and we could lose customers that may be difficult to replace. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Financial Risks

Our international businesses and operations expose us to foreign currency exchange rate and inflation risks.

Our operations in Mexico pose foreign currency exchange rate and inflation risks. Exchange and inflation rates with respect to Mexico and fluctuations in those rates may have an impact on the revenue, cash flows and costs from our international operations, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We may attempt to hedge cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments, but these hedges may not fully achieve our objectives of mitigating earnings volatility that would otherwise occur due to exchange rate fluctuations. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations for entities whose functional currencies are not the U.S. dollar. Moreover, Mexico has experienced periods of high inflation and exchange rate instability in the past, and severe devaluation of the Mexican peso could result in governmental intervention to institute restrictive exchange control policies, as has occurred before in Mexico and other Latin American countries. We discuss our foreign currency exposure at our Mexican subsidiaries in “Part II – Item 7. MD&A” and “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Our businesses are exposed to fluctuations in commodity prices.

We buy energy-related commodities from time to time for pipeline operations, LNG facilities or power plants to satisfy contractual obligations with customers. The regional and other markets in which we purchase these commodities are competitive and can be subject to significant pricing volatility as a result of many factors, including inflation, adverse weather conditions, supply and demand changes, availability of competitively priced alternative energy sources, commodity production levels and storage capacity, energy and environmental legislation and regulations, and economic and financial market conditions. Our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities we buy change in a direction or manner not anticipated and for which we have not provided adequately through purchase or sale commitments or other hedging transactions.

Legal and Regulatory Risks

Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical and management oversight risks and challenges.

We own or have interests in a variety of energy infrastructure assets in Mexico, and we do business with companies based in foreign markets, including particularly our LNG export operations. Conducting these activities in foreign jurisdictions subjects us to complex management, security, political, legal, economic and financial risks that vary by country, many of which may differ from and potentially be greater than those associated with our wholly domestic businesses, and the occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. These risks include the following and the other risks discussed in this risk factor below:

• compliance with tax, trade, environmental and other foreign laws and regulations, including legal limitations on ownership in some foreign countries and inadequate or inconsistent enforcement of regulations
• actions by local regulatory bodies, including setting rates and tariffs that may be earned by or charged to our businesses
• adverse changes in social, political, economic or market conditions or the stability of foreign governments
• adverse rulings by foreign courts or tribunals; challenges obtaining, maintaining and complying with permits or approvals; difficulty enforcing contractual and property rights; and differing legal standards
• expropriation or theft of assets
• demand for hydrocarbon fuels, such as natural gas imported from the U.S., may be impacted by geopolitical factors
• with respect to our non-utility international business activities, changes in the priorities and budgets of international customers, which may be driven by many of the factors listed above, among others

Mexican Government Influence on Economic and Energy Matters

The Mexican government exercises significant and increasing influence over the Mexican energy sector and has adopted or proposed additional changes that, in each case, could impact private investment in this sector.

Mexican governmental actions in the past several years in the electricity market include resolutions, orders, decrees, regulations and proposed and adopted amendments to Mexican law that could, among other things, threaten the prospects for private-party renewable energy generation in the country, limit the ability to dispatch renewable energy and receive or maintain operational permits, and increase costs of electricity for legacy renewables and cogeneration energy contract holders. We discuss some of these actions in Note 16 of the Notes to Consolidated Financial Statements. Moreover, reforms to centralize and de-privatize the electricity market in Mexico have been proposed previously and could be reintroduced in the future.

With respect to midstream and downstream activities, Mexico’s Hydrocarbons Law gives SENER and the CRE significant powers to suspend permits when a danger to national security, energy security, or the national economy is foreseen and to revoke permits under certain other circumstances, including for a failure to comply with certain minimum storage and other requirements or for violations of certain provisions established by SENER or the Hydrocarbons Law, as applicable.

If future governmental actions are proposed and passed or otherwise become effective, if efforts to enjoin enforcement or suspend or overturn adopted governmental actions fail, or if other similar actions by the Mexican government are taken to curb private-party participation in the energy sector, including through further amendments to Mexican laws, rules or the constitution or increased investigative and enforcement activities, it may impact our ability to operate our facilities at existing levels or at all, result in increased costs for Sempra Infrastructure and its customers, adversely affect our ability to develop new projects, result in decreased revenues and cash flows, and negatively impact our ability to recover the carrying values of our investments in Mexico, any of which may have a material adverse effect on our business, results of operations, financial condition, cash flows and/or prospects.

U.S. and Mexican Laws and Foreign Policy

Our international business activities are subject to U.S. and Mexican laws and regulations related to foreign operations or doing business internationally, including the U.S. Foreign Corrupt Practices Act, the Mexican Federal Anticorruption Law in Public Contracting (Ley Federal Anticorrupción en Contrataciones Públicas) and similar laws, and are sensitive to U.S. and Mexican foreign policy, trade policy and other geopolitical factors. The current and the last U.S. Administrations have taken different stances with respect to international trade agreements, tariffs, immigration policy and other matters of foreign policy that impact trade and foreign relations. Shifts in foreign policy could create uncertainty and result in or increase adverse effects on our businesses. Violations or alleged violations of the laws referred to above, as well as foreign policy positions that adversely affect imports and exports between the U.S., Mexican and other foreign companies with which we conduct business, could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

We face risks related to unsettled property rights and titles in Mexico.

We are engaged in disputes regarding our title to the property in Mexico where our ECA Regas Facility is situated and our ECA LNG projects are expected to be situated, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. In addition, we may have or seek to obtain long-term leases or rights-of-way from governmental agencies or other third parties to operate our energy infrastructure on land we do not own. In addition to the risks associated with such property ownership and use that we describe above under “Risks Related to All Sempra Businesses – Operational Risks,” disputes regarding ownership or rights to any of these properties could lead to difficulties finding or maintaining suitable partners, customers and project financing arrangements and could hinder or halt our ability to construct and, if completed, operate the affected facilities or proposed projects. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

Sempra Infrastructure’s energy infrastructure assets may be considered by the Mexican government to be a public service or essential for the provision of a public service, in which case these assets and the related businesses could be subject to expropriation or nationalization, loss of concessions, renegotiation or annulment of existing contracts, and other similar risks. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

CYBERSECURITY RISK MANAGEMENT

Sempra, SDG&E and SoCalGas have developed and implemented cybersecurity risk management processes intended to protect the confidentiality, integrity, and availability of our critical infrastructure, systems and information. These cybersecurity risk management processes include cybersecurity incident response plans that are integrated into each entity’s respective enterprise risk management and emergency management programs.

Our cybersecurity processes are largely designed and assessed based on the National Institute of Standards and Technology Cybersecurity Framework and the DOE’s Cybersecurity Capability Maturity Model standards. This does not imply that we meet any technical standards, specifications, or requirements, only that we use these standards as a guide to help us identify, assess, and manage cybersecurity risks relevant to our business.

Our cybersecurity risk management processes include:

• risk assessments performed by internal personnel and third-party advisors designed to help identify material cybersecurity risks to our critical systems, information, services, and our broader enterprise information technology environments
• information security teams principally responsible for developing and implementing (1) cybersecurity risk assessment processes, (2) information security controls, and (3) response plans to cybersecurity incidents
• the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our information security controls
• cybersecurity awareness training and policies designed to address social engineering attacks targeting employees and contractors
• cybersecurity incident response plans that include procedures for responding to certain cybersecurity incidents
• risk management processes for third-party service providers, suppliers, and vendors

We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected or are reasonably likely to materially affect our results of operations, financial condition, cash flows and/or prospects.

CYBERSECURITY GOVERNANCE

Sempra’s, SDG&E’s and SoCalGas’ respective boards of directors consider cybersecurity risk as part of their risk oversight function. The Sempra board of directors has delegated to its SST Committee, which is entirely composed of independent directors under the independence standards established by the NYSE, oversight of cybersecurity and other information and operational technology risks. The SST Committee reports to the Sempra board of directors regarding the Committee’s activities, including those related to cybersecurity. The SST Committee receives briefings on cybersecurity topics from Sempra’s chief information security officer, internal information security staff or external experts in part for continuing education on topics that impact public companies. The SST Committee as well as the SDG&E and SoCalGas boards of directors oversee management’s implementation of our cybersecurity risk management processes and receive regular reports from management on our material cybersecurity risks. In addition, management updates the SST Committee and SDG&E and SoCalGas boards of directors about certain cybersecurity incidents. The SDG&E and SoCalGas boards of directors receive briefings from SDG&E’s and SoCalGas’ chief information officer and internal information security staff. SDG&E’s and SoCalGas’ boards of directors also have formed safety committees that, at times, may oversee the matters described above on behalf of those companies’ respective boards of directors.

We have formed cybersecurity councils to provide overall corporate oversight for managing material risks from cybersecurity threats. The cybersecurity councils meet regularly to receive updates on cybersecurity developments at Sempra and our consolidated entities from their cybersecurity management teams.

Our cybersecurity management teams supervise efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, which may include briefings from internal information security personnel; threat intelligence and other information obtained from governmental, public or private sources, including external consultants engaged by us; and alerts and reports produced by information security tools deployed in the information technology environment. Cybersecurity management also supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Sempra’s director of cybersecurity governance & chief information security officer provides additional oversight and support for the operational cybersecurity activities at our consolidated entities.

We have also formed materiality assessment teams, which include chief information security officers, chief information officers, chief risk officers, chief accounting officers or chief financial officers, and general counsels, to help assess the materiality of certain cybersecurity incidents.

The cybersecurity councils, cybersecurity management teams and materiality assessment teams include members with decades of operational experience as cybersecurity professionals as well as management with decades of service in the areas of information and operational technology and legal, compliance, financial reporting and enterprise risk management. Some of these members hold degrees and certifications that we believe enhance our ability to manage and respond to cybersecurity risks, including, among others, bachelor’s and/or master’s degrees in cybersecurity and computer science as well as certified information systems security professional, certified incident handler, and certified information security manager certifications.

We own or lease land, warehouses, offices, operating and maintenance centers, shops and service facilities necessary to conduct our businesses. Each of our Registrants currently has adequate space and, if we need more space, we believe it is readily available. We discuss properties related to our electric, natural gas and energy infrastructure operations in “Part I – Item 1. Business” and Note 1 of the Notes to Consolidated Financial Statements.

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) or environmental proceedings described in Item 103(c)(3) of SEC Regulation S-K except for the matters described in Note 16 of the Notes to Consolidated Financial Statements, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A.”

OVERVIEW

This combined MD&A includes the operational and financial results of the following three Registrants:

• Sempra is a California-based holding company with energy infrastructure investments in North America. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers.
• SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
• SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California.

In the fourth quarter of 2023, Sempra realigned its reportable segments to reflect changes in how the CODM oversees our three platforms: Sempra California, Sempra Texas Utilities and Sempra Infrastructure. Our former SDG&E and SoCalGas reportable segments were combined into one operating and reportable segment, Sempra California, which is consistent with how the CODM assesses performance due to the similarities of their operations, including geographic location and regulatory framework in California.

Sempra’s historical segment disclosures have been restated to conform with the current presentation, so that all discussions reflect the revised segment information of its three reportable segments:

• Sempra California
• Sempra Texas Utilities
• Sempra Infrastructure

SDG&E and SoCalGas each has one reportable segment.

Our 2023 operational and financial results reflect our mission to be North America’s premier energy infrastructure company. Key events in 2023 include:

• Sempra celebrated its 25th anniversary
• Our company changed its legal name from Sempra Energy to Sempra
• We completed the offering of 17,142,858 shares of Sempra’s common stock at a public offering price of $70.00 per share, pursuant to forward sale agreements
• The CCM was triggered and approved for SDG&E and SoCalGas, which increases each company’s respective ROE by 70 bps effective January 1, 2024
• The CPUC authorized an increase to the Aliso Canyon natural gas storage facility’s capacity from 41.16 Bcf to 68.6 Bcf
• Oncor received a final order from the PUCT on its comprehensive base rate review
• Sempra Infrastructure reached a final investment decision and started construction on the PA LNG Phase 1 project and Port Arthur Pipeline Louisiana Connector and Louisiana Storage projects
• SI Partners completed the sales of a 30% and 42% NCI in the PA LNG Phase 1 project to ConocoPhillips and KKR Denali, respectively
• We invested $8.8 billion in capital expenditures and investments

On August 2, 2023, Sempra’s board of directors declared a two-for-one split of Sempra’s common stock in the form of a 100% stock dividend for shareholders of record at the close of business on August 14, 2023. Sempra’s common stock began trading on a post-split basis effective August 22, 2023. Except as expressly noted, all share and per share information related to issued and outstanding common stock has been retroactively adjusted to reflect the stock split and is presented on a post-split basis herein.

RESULTS OF OPERATIONS BY REGISTRANT

Throughout the MD&A, our references to earnings represent earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted, and before foreign currency and inflation effects and NCI, where applicable.

We discuss herein Sempra’s results of operations and significant changes in earnings (losses), revenues and costs by segment, as well as Parent and other, for the year ended December 31, 2023 compared to the year ended December 31, 2022 and the year ended December 31, 2022 compared to the year ended December 31, 2021. We also discuss herein the impact of foreign currency and inflation rates on Sempra’s results of operations.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

(Dollars and shares in millions, except per share amounts)

EARNINGS (LOSSES) BY SEGMENT

(Dollars in millions)

(1) Includes intercompany eliminations recorded in consolidation and certain corporate costs.

Sempra California

Sempra California’s earnings are comprised of SDG&E and SoCalGas. Because changes in SDG&E’s and SoCalGas’ cost of natural gas and/or electricity are recovered in rates, changes in these costs are offset in the changes in revenues and therefore do not impact earnings, other than potential impacts related to the GCIM for SoCalGas that we describe below. In addition to the changes in cost or market prices, natural gas or electric revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized amounts. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 4 of the Notes to Consolidated Financial Statements.

In 2023 compared to 2022, the increase in earnings of $233 million (15%) was primarily due to:

• $199 million charge in 2022 relating to litigation and regulatory matters pertaining to the Leak
• $39 million higher net regulatory interest income
• $37 million higher income tax benefits primarily from flow-through items, which includes $25 million related to income tax benefits in 2023 for previously unrecognized income tax benefits pertaining to gas repairs expenditures
• $30 million higher CPUC base operating margin, net of operating expenses and $46 million from lower authorized cost of capital
• $21 million higher electric transmission margin
• $13 million higher regulatory awards approved by the CPUC
• $10 million in penalties in 2022 related to energy efficiency and advocacy OSCs

Offset by:

• $90 million higher net interest expense
• $16 million lower income tax benefit from the resolution of prior year income tax items

In 2022 compared to 2021, the increase in earnings of $1.1 billion was primarily due to:

• $949 million decrease in charges relating to litigation and regulatory matters pertaining to the Leak comprised of a $199 million charge in 2022 compared to $1,148 million in 2021
• $161 million higher CPUC base operating margin, net of operating expenses
• $21 million lower net income tax expense primarily from flow-through items, net of lower associated regulatory revenues
• $20 million higher income tax benefit from the resolution of prior year income tax items
• $15 million higher net regulatory interest income
• $14 million higher AFUDC equity

Offset by:

• $52 million higher net interest expense
• $10 million in penalties in 2022 related to energy efficiency and advocacy OSCs

Sempra Texas Utilities

In 2023 compared to 2022, the decrease in earnings of $42 million (6%) was primarily due to lower equity earnings from Oncor Holdings driven by:

• higher interest expense and depreciation expense attributable to invested capital
• higher O&M
• write-off of rate base disallowances in 2023 resulting from the PUCT’s final order in Oncor’s comprehensive base rate review

Offset by:

• higher revenues attributable to:
• rate updates to reflect increases in invested capital
• increases in transmission billing units
• new base rates implemented in May 2023
• customer growth

Offset by:

• lower customer consumption primarily attributable to weather

In 2022 compared to 2021, the increase in earnings of $120 million (19%) was primarily due to higher equity earnings from Oncor Holdings driven by:

• higher revenues attributable to:
• rate updates to reflect increases in invested capital
• higher customer consumption attributable primarily to weather
• customer growth

Offset by:

• higher depreciation expense and interest expense attributable to invested capital
• higher O&M

Sempra Infrastructure

In 2023 compared to 2022, the increase in earnings of $567 million was primarily due to:

• $1.1 billion from asset and supply optimization driven by unrealized gains in 2023 compared to unrealized losses in 2022 on commodity derivatives due to changes in natural gas prices
• $112 million lower income tax expense in 2023 attributable to NCI’s share of higher U.S. partnerships’ pretax income
• $99 million from the transportation business driven by higher equity earnings and revenues, including the cumulative impact of new tariffs going into effect in June 2023 for certain pipelines in Mexico

Offset by:

• $397 million decrease from $543 million earnings attributable to NCI in 2023 compared to $146 million earnings attributable to NCI in 2022 primarily due to an increase in SI Partners net income and from the sale of a 10% NCI in SI Partners to ADIA in June 2022
• $127 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $346 million unfavorable impact in 2023 compared to a $219 million unfavorable impact in 2022
• $61 million lower net income tax benefit primarily from the remeasurement of certain deferred income taxes and outside basis differences in a JV investment
• $58 million lower equity earnings from Cameron LNG JV driven by lower revenues from excess LNG and higher interest expense
• $37 million higher O&M from a provision for expected credit losses on a customer’s past due receivable balance
• $21 million from the LNG business driven by higher development costs and certain non-capitalized expenses from projects under construction
• $19 million higher net interest expense due to $27 million net unrealized losses in 2023 compared to $27 million net unrealized gains in 2022 on a contingent interest rate swap related to the PA LNG Phase 1 project and higher interest rates and borrowings on committed lines of credit, offset by higher capitalization of interest expense on projects under construction

In 2022 compared to 2021, the decrease in earnings of $372 million was primarily due to:

• $431 million from asset and supply optimization driven by $283 million losses in 2022 compared to $148 million earnings in 2021 driven by higher unrealized losses on commodity derivatives due to changes in natural gas prices, offset by higher diversion fees
• $169 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, net of foreign currency derivative effects, comprised of a $216 million unfavorable impact in 2022 compared to a $47 million unfavorable impact in 2021

Offset by:

• $79 million higher equity earnings from Cameron LNG JV primarily from higher revenues from excess LNG production and maintenance revenues
• $50 million higher net income tax benefit primarily from the remeasurement of certain deferred income taxes and outside basis differences in JV investments
• $50 million lower net interest expense, including $37 million in charges associated with hedge termination costs and a write-off of unamortized debt issuance costs from the early redemptions of debt in October 2021 and $27 million net unrealized gains in 2022 on a contingent interest rate swap related to the proposed PA LNG Phase 1 project
• $42 million from the transportation business in Mexico driven by higher rates and higher equity earnings at IMG excluding unfavorable impact from foreign currency and inflation

Parent and Other

In 2023 compared to 2022, the decrease in losses of $178 million (38%) was primarily due to:

• $120 million deferred income tax expense in 2022 associated with the change in our indefinite reinvestment assertion related to our foreign subsidiaries
• $63 million from $13 million net investment gains in 2023 compared to $50 million net investment losses in 2022 on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan
• $40 million equity earnings in 2023 from our investment in RBS Sempra Commodities based on a legal settlement, which we discuss in Note 16 of the Notes to Consolidated Financial Statements
• $23 million income tax benefit in 2023 from the remeasurement of certain deferred income taxes

Offset by:

• $68 million higher net interest expense
• $41 million lower income tax benefit from changes to a valuation allowance against certain tax credit carryforwards

In 2022 compared to 2021, the increase in losses of $30 million (7%) was primarily due to:

• $120 million deferred income tax expense associated with the change in our indefinite reinvestment assertion related to our foreign subsidiaries
• $79 million from $50 million net investment losses in 2022 compared to $29 million net investment gains in 2021 on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan
• $50 million equity earnings in 2021 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs
• $26 million gain on the sale of PXiSE in December 2021

Offset by:

• $92 million in charges associated with make-whole premiums and a write-off of unamortized discount and debt issuance costs from the early redemptions of debt in December 2021
• $72 million net income tax expense related to the utilization of a deferred income tax asset upon completing the sale of a 20% NCI in SI Partners to KKR Pinnacle in October 2021
• $58 million decrease from $49 million income tax benefit in 2022 compared to $9 million income tax expense in 2021 from changes to a valuation allowance against certain tax credit carryforwards
• $19 million lower preferred dividends due to the mandatory conversion of all series B preferred stock in July 2021

SIGNIFICANT CHANGES IN REVENUES AND COSTS

The regulatory framework permits SoCalGas and SDG&E to recover certain program expenditures and other costs authorized by the CPUC (referred to as “refundable programs”).

Utilities: Natural Gas Revenues and Cost of Natural Gas

Our utilities revenues include natural gas revenues at Sempra California and Sempra Infrastructure, which includes Ecogas. Intercompany revenues are eliminated in Sempra’s Consolidated Statements of Operations.

SoCalGas and SDG&E operate under a regulatory framework that permits the cost of natural gas purchased for customers (residential and small commercial and industrial customers, also referred to as core customers for SoCalGas) to be passed through to customers in rates substantially as incurred and without markup. The GCIM provides for SoCalGas to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between SoCalGas and its core customers. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements.

UTILITIES: NATURAL GAS REVENUES AND COST OF NATURAL GAS

(Dollars in millions)

(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2023 compared to 2022, Sempra’s natural gas revenue increased by $1.6 billion (21%) to $9.5 billion driven by Sempra California, which included:

• $1.2 billion increase in cost of natural gas sold, which we discuss below
• $414 million higher revenues associated with refundable programs, which are fully offset in O&M
• $110 million higher CPUC-authorized revenues
• $47 million higher revenues from incremental and balanced capital projects
• $40 million higher non-service components of net periodic benefit cost, which fully offsets in other income, net
• $23 million higher franchise fee revenues
• $18 million higher regulatory awards approved by the CPUC

Offset by:

• $171 million lower regulatory revenues in 2023 from the election to change the tax accounting method under Revenue Procedure 2023-15, which are offset in income tax expense
• $26 million lower regulatory revenues in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures, which are offset in income tax expense

In 2023 compared to 2022, Sempra’s cost of natural gas increased by $1.1 billion (43%) to $3.7 billion primarily due to a $1.2 billion increase at Sempra California, which included:

• $1.1 billion higher average natural gas prices
• $123 million higher volumes driven by weather

In 2022 compared to 2021, Sempra’s natural gas revenues increased by $1.5 billion (24%) to $7.9 billion driven by Sempra California, which included:

• $984 million increase in cost of natural gas sold, which we discuss below
• $237 million higher revenues associated with refundable programs, which are fully offset in O&M
• $156 million higher CPUC-authorized revenues
• $100 million higher revenues from incremental and balanced capital projects
• $35 million higher revenues associated with impacts resulting from changes in tax laws tracked in the income tax expense memorandum account

In 2022 compared to 2021, Sempra’s cost of natural gas increased by $1.0 billion to $2.6 billion primarily due to a $984 million increase at Sempra California due to higher average natural gas prices.

Utilities: Electric Revenues and Cost of Electric Fuel and Purchased Power

Our utilities revenues include electric revenues at Sempra California, substantially all of which is at SDG&E. Intercompany revenues are eliminated in Sempra’s Consolidated Statements of Operations.

SDG&E operates under a regulatory framework that permits it to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered or refunded in subsequent periods through rates.

Utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to/from the California ISO.

UTILITIES: ELECTRIC REVENUES AND COST OF ELECTRIC FUEL AND PURCHASED POWER

(Dollars in millions)

(1) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2023 compared to 2022, Sempra’s electric revenues decreased by $449 million (9%) to $4.3 billion driven by Sempra California, which included:

• $549 million lower cost of electric fuel and purchased power, which we discuss below
• $197 million in 2023 from the recognition of investment tax credits from standalone energy storage projects, which are offset in income tax expense

Offset by:

• $97 million higher revenues from incremental and balanced capital projects
• $92 million higher revenues associated with refundable programs, which are fully offset in O&M
• $50 million higher revenues from transmission operations
• $45 million higher CPUC-authorized revenues

In 2023 compared to 2022, Sempra’s cost of electric fuel and purchased power decreased by $562 million to $375 million primarily due to a $549 million decrease at Sempra California, which included:

• $396 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs and lower market prices
• $170 million lower purchased power due to higher excess capacity sales to third parties
• $157 million lower utility-owned generation costs
• $65 million higher realized gains on derivative contracts for fixed-price natural gas, which are entered into to hedge the cost of electric fuel, and GHG allowances

Offset by:

• $259 million lower sales to the California ISO due to lower market prices

In 2022 compared to 2021, Sempra’s electric revenues increased by $125 million (3%) to $4.8 billion driven by Sempra California, which included:

• $70 million higher CPUC-authorized revenues
• $68 million higher revenues associated with the wildfire mitigation plan at Sempra California
• $35 million higher revenues associated with refundable programs, which are fully offset in O&M
• $18 million higher revenues from transmission operations
• $14 million higher revenues associated with lower income tax benefits from flow-through items

Offset by:

• $75 million lower cost of electric fuel and purchased power, which we discuss below

In 2022 compared to 2021, Sempra’s cost of electric fuel and purchased power decreased by $73 million (7%) to $937 million primarily due to a $75 million decrease at Sempra California, which included:

• $451 million higher sales to the California ISO due to higher market prices

Offset by:

• $191 million higher purchased power from the California ISO due to higher market prices, net of lower customer demand from departing load now served by CCAs
• $185 million higher utility-owned generation costs

Energy-Related Businesses: Revenues and Cost of Sales

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES

(Dollars in millions)

(1) Includes eliminations of intercompany activity.

(2) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.

In 2023 compared to 2022, Sempra’s revenues from energy-related businesses increased by $1.1 billion to $2.9 billion primarily due to:

• $1.2 billion increase in revenues from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
• $1.3 billion primarily driven by $710 million unrealized gains in 2023 compared to $660 million unrealized losses in 2022 on commodity derivatives offset by $223 million primarily from lower natural gas prices

Offset by:

• $71 million lower LNG sales
• $33 million primarily from lower LNG diversion fees

Offset by:

• $102 million decrease in revenues from TdM mainly due to lower power prices

In 2023 compared to 2022, the cost of sales for Sempra’s energy-related businesses decreased by $394 million (42%) to $548 million primarily due to lower natural gas and LNG purchases related to asset and supply optimization.

In 2022 compared to 2021, Sempra’s revenues from energy-related businesses decreased by $78 million (4%) to $1.8 billion primarily due to:

• $344 million decrease in revenues from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
• $498 million primarily driven by $639 million from higher unrealized losses on commodity derivatives offset by $148 million from higher natural gas prices and volumes

Offset by:

• $83 million higher diversion fees due to higher natural gas prices
• $71 million higher LNG sales

Offset by:

• $143 million increase in revenues from TdM mainly due to higher power prices offset by lower volumes from scheduled major maintenance completed in March 2022, which resulted in increased plant reliability
• $53 million higher transportation revenues driven by higher rates
• $46 million higher revenues from the renewables business due to Border Solar and the second phase of ESJ being placed in service in March 2021 and January 2022, respectively, the acquisition of ESJ in March 2021 and higher transmission rates
• $5 million higher revenues from the Veracruz and Mexico City terminals placed in service in March and July of 2021, respectively, offset by an $18 million selling profit on a sales-type lease relating to the commencement of a rail facility lease at the Veracruz terminal in the third quarter of 2021 and a remeasurement of an operating lease

In 2022 compared to 2021, the cost of sales for Sempra’s energy-related businesses increased by $331 million to $942 million primarily due to:

• $257 million driven by higher natural gas and LNG purchases related to asset and supply optimization
• $65 million at TdM driven by higher natural gas prices offset by lower volumes from scheduled major maintenance completed in March 2022

Operation and Maintenance

OPERATION AND MAINTENANCE

(Dollars in millions)

(1) Includes eliminations of intercompany activity.

In 2023 compared to 2022, Sempra’s O&M increased by $713 million (15%) to $5.5 billion primarily due to:

• $579 million increase at Sempra California due to:
• $506 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue
• $73 million higher non-refundable operating costs
• $137 million increase at Sempra Infrastructure due to:
• $52 million from a provision for expected credit losses on a customer’s past due receivable balance
• $38 million higher development costs and certain non-capitalized expenses from projects under construction
• $21 million higher purchased services
• $12 million higher operating cost due to remeasurement of operating leases at the refined products terminals in 2022

In 2022 compared to 2021, Sempra’s O&M increased by $405 million (9%) to $4.7 billion primarily due to:

• $305 million increase at Sempra California due to:
• $272 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue
• $33 million higher non-refundable operating costs
• $106 million increase at Sempra Infrastructure due to:
• $28 million at the transportation business due to maintenance on pipelines and new compressor stations and higher administrative costs
• $28 million higher development costs and purchased services
• $20 million from the renewables business primarily due to construction repairs and maintenance at Ventika
• $19 million due to the start of commercial operations of the Veracruz and Mexico City terminals in March and July of 2021, respectively
• $10 million higher operating costs at TdM from higher purchased materials and services due to scheduled major maintenance completed in March 2022

Offset by:

• $16 million lower operating cost due to remeasurement of operating leases at the refined products terminals

Aliso Canyon Litigation and Regulatory Matters

In 2022 and 2021, Sempra California recorded charges of $259 million and $1,593 million, respectively, relating to litigation and regulatory matters pertaining to the Leak. We describe these charges in Note 16 of the Notes to Consolidated Financial Statements.

Gain on Sale of Assets

In 2021, Parent and other recognized a $36 million gain on the sale of PXiSE.

Other Income, Net

In 2023 compared to 2022, Sempra’s other income, net, increased by $107 million to $131 million primarily due to:

• $70 million increase from $28 million net investment gains in 2023 compared to $42 million net investment losses in 2022 primarily on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other
• $53 million higher net interest income on regulatory balancing accounts at Sempra California primarily due to higher commercial paper rates
• $19 million increase from $6 million gains in 2023 compared to $13 million losses in 2022 from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions primarily at Sempra Infrastructure, including:
• $15 million higher from $2 million gains in 2023 compared to $13 million losses in 2022 on other foreign currency transactional effects
• $11 million foreign currency losses in 2022 on a Mexican peso-denominated loan to IMG, which is fully offset in equity earnings

Offset by:

• $6 million lower gains on cross-currency swaps as a result of fluctuation of the Mexican peso
• $10 million in penalties in 2022 related to energy efficiency and advocacy OSCs at Sempra California

Offset by:

• $47 million higher non-service components of net periodic benefit cost, including $46 million at Sempra California

In 2022 compared to 2021, Sempra’s other income, net, decreased by $34 million to $24 million primarily due to:

• $92 million decrease due to $42 million net investment losses in 2022 compared to $50 million net investment gains in 2021 on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other
• $10 million in penalties at Sempra California in 2022 related to energy efficiency and advocacy OSCs

Offset by:

• $33 million lower losses from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions primarily at Sempra Infrastructure, including:
• $40 million lower from $12 million gains in 2022 compared to $28 million losses in 2021 on foreign currency derivatives and cross-currency swaps as a result of fluctuation of the Mexican peso
• $12 million lower foreign currency losses on a Mexican peso-denominated loan to IMG, which is offset in equity earnings

Offset by:

• $18 million higher from $13 million losses in 2022 compared to $5 million gains in 2021 on other foreign currency transactional effects
• $20 million higher net interest income on regulatory balancing accounts at Sempra California
• $10 million higher AFUDC equity, including $14 million at Sempra California
• $8 million lower non-service components of net periodic benefit cost

We provide further details of the components of other income, net, in Note 1 of the Notes to Consolidated Financial Statements.

Interest Expense

In 2023 compared to 2022, Sempra’s interest expense increased by $255 million (24%) to $1.3 billion primarily due to:

• $135 million at Sempra California primarily from higher debt balances from debt issuances and higher interest rates
• $94 million at Parent and other from higher interest rates and borrowings on commercial paper and higher debt balances from debt issuances
• $25 million at Sempra Infrastructure primarily due to:
• $80 million higher from $33 million net unrealized losses and $14 million settlement in 2023 compared to $33 million net unrealized gains in 2022 on a contingent interest rate swap related to the PA LNG Phase 1 project that we discuss in Note 11 of the Notes to Consolidated Financial Statements
• $44 million primarily from higher interest rates and borrowings on committed lines of credit

Offset by:

• $99 million lower interest expense due to higher capitalization of interest expense on projects under construction

In 2022 compared to 2021, Sempra’s interest expense decreased by $144 million (12%) to $1.1 billion primarily due to:

• $121 million at Parent and other primarily due to $126 million in charges associated with make-whole premiums and a write-off of unamortized discount and debt issuance costs from the early redemptions of debt in December 2021, offset by higher debt balances from debt issuances
• $101 million at Sempra Infrastructure primarily due to:
• $54 million in charges associated with hedge termination costs and a write-off of unamortized debt issuance costs from the early redemptions of debt in October 2021
• $33 million net unrealized gains in 2022 on a contingent interest rate swap related to the proposed PA LNG Phase 1 project

Offset by:

• $78 million at Sempra California primarily from higher debt balances from debt issuances

Income Taxes

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES

(Dollars in millions)

(1) We discuss how we recognize equity earnings in Note 6 of the Notes to Consolidated Financial Statements.

We report as part of our pretax results the income or loss attributable to NCI. However, we do not record income taxes for a portion of this income or loss, as some of our entities with NCI are currently treated as partnerships for U.S. income tax purposes, and thus we are only liable for income taxes on the portion of the earnings that are allocated to us. Our pretax income, however, includes 100% of these entities. If our entities with NCI grow, and if we continue to invest in such entities, the impact on our ETR may become more significant.

Under the IRA, in 2023, the scope of projects eligible for investment tax credits was expanded to include standalone energy storage projects. The IRA also provided an election that permits investment tax credits related to standalone energy storage projects to be returned to utility customers over a period that is shorter than the life of the applicable asset. Under this election, Sempra recorded an income tax benefit of $142 million for these investment tax credits, offset by a regulatory liability, which reduced Sempra’s ETR in 2023.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. Sempra intends to elect this change in tax accounting method in its 2023 income tax return filing and has recorded an estimated income tax benefit of $131 million in 2023. Additionally, Sempra updated its assessment of prior years’ unrecognized income tax benefits and recorded an income tax benefit of $43 million in 2023 for previously unrecognized income tax benefits pertaining to gas repairs expenditures. Sempra recorded associated regulatory liabilities for the portion of these benefits that will be flowed through to customers in the future.

In 2023 compared to 2022, Sempra’s income tax expense decreased by $66 million (12%) primarily due to:

• $142 million income tax benefit in 2023 from the recognition of investment tax credits from standalone energy storage projects
• $120 million deferred income tax expense in 2022 associated with the change in our indefinite reinvestment assertion related to our foreign subsidiaries
• higher income tax benefits from flow-through items, including a $131 million benefit for the election to change the tax accounting method under Revenue Procedure 2023-15
• $112 million lower income tax expense in 2023 attributable to NCI’s share of higher U.S. partnerships’ pretax income
• $43 million income tax benefit in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures

Offset by:

• higher pretax income
• $114 million from $283 million income tax expense in 2023 compared to $169 million income tax expense in 2022 from foreign currency and inflation effects on our monetary positions in Mexico
• $60 million income tax benefit in 2022 associated with charges relating to litigation and regulatory matters pertaining to the Leak
• $41 million lower income tax benefit from changes to a valuation allowance against certain tax credit carryforwards

In 2022 compared to 2021, Sempra’s income tax expense increased by $457 million in 2022 compared to 2021 primarily due to:

• $385 million from a $60 million income tax benefit in 2022 compared to $445 million income tax benefit in 2021 associated with charges relating to litigation and regulatory matters pertaining to the Leak
• $165 million from $169 million income tax expense in 2022 compared to $4 million income tax expense in 2021 from foreign currency and inflation effects on our monetary positions in Mexico and associated derivatives
• $120 million deferred income tax expense associated with the change in our indefinite reinvestment assertion related to our foreign subsidiaries
• lower income tax benefits from flow-through items

Offset by:

• $72 million net income tax expense related to the utilization of a deferred income tax asset upon completing the sale of a 20% NCI in SI Partners to KKR in October 2021
• $58 million from a $49 million income tax benefit in 2022 compared to $9 million income tax expense in 2021 from changes to a valuation allowance against certain tax credit carryforwards
• $28 million higher net income tax benefit in 2022 from the remeasurement of certain deferred income taxes
• $22 million higher income tax benefit in 2022 from the resolution of prior year income tax items

We discuss the impact of foreign currency exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Notes 1 and 8 of the Notes to Consolidated Financial Statements for further details about our accounting for income taxes and items subject to flow-through treatment.

Equity Earnings

In 2023 compared to 2022, Sempra’s equity earnings decreased by $17 million (1%) remaining at $1.5 billion primarily due to:

• $73 million at Cameron LNG JV due to lower revenues from excess LNG and higher interest expense
• $41 million at Oncor Holdings driven by:
• higher interest expense and depreciation expense attributable to invested capital
• higher O&M
• write-off of rate base disallowances in 2023 resulting from the PUCT’s final order in Oncor’s comprehensive base rate review

Offset by:

• higher revenues attributable to:
• rate updates to reflect increases in invested capital
• increases in transmission billing units
• new base rates implemented in May 2023
• customer growth

Offset by:

• lower customer consumption primarily attributable to weather
• $28 million at IMG due to higher interest expense and foreign currency effects, including $11 million foreign currency gains in 2022 on IMG’s Mexican peso-denominated loans from its JV owners, which is fully offset in other income, net

Offset by:

• $85 million at TAG Norte due to higher revenues, including the cumulative impact of new tariffs going into effect in June 2023, offset by higher income tax expense
• $40 million related to our investment in RBS Sempra Commodities based on a legal settlement

In 2022 compared to 2021, Sempra’s equity earnings increased by $155 million (12%) to $1.5 billion primarily due to:

• $118 million at Oncor Holdings due to:
• higher revenues from rate updates to reflect increases in invested capital
• higher customer consumption attributable primarily to weather and customer growth

Offset by:

• higher depreciation expense and interest expense attributable to invested capital
• higher O&M
• $100 million at Cameron LNG JV primarily due to excess LNG production and maintenance revenues

Offset by:

• $50 million in 2021 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs
• $15 million at IMG due to higher income tax expense and foreign currency effects, including $12 million lower foreign currency gains on IMG’s Mexican peso-denominated loans from its JV owners, which is fully offset in other income, net, offset by lower interest expense

Earnings Attributable to Noncontrolling Interests

In 2023 compared to 2022, Sempra’s earnings attributable to NCI increased by $397 million to $543 million primarily due to:

• $310 million increase due to an increase in SI Partners’ net income
• $87 million increase as a result of a decrease in our ownership interest in SI Partners and SI Partners subsidiaries

In 2022 compared to 2021, Sempra’s earnings attributable to NCI increased by $1 million (1%) to $146 million primarily due to:

• $120 million increase as a result of a decrease in our ownership interest in SI Partners offset by an increase in our ownership interest in IEnova

Offset by:

• $121 million decrease due to a decrease in SI Partners subsidiaries net income

Preferred Dividends

In 2022 compared to 2021, preferred dividends decreased by $19 million to $44 million due to the conversion of all series B preferred stock in July 2021.

IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS

Because our natural gas distribution utility in Mexico, Ecogas, uses its local currency as its functional currency, its revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra’s results of operations.

Foreign Currency Translation

Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra’s comparative results of operations. The change in our earnings as a result of foreign currency translation rates was higher by $3 million in 2023 compared to 2022 and negligible in 2022 compared to 2021.

Transactional Impacts

Although the financial statements of most of our Mexican subsidiaries and JVs have the U.S. dollar as the functional currency, some transactions may be denominated in the local currency; such transactions are remeasured into U.S. dollars. This remeasurement creates transactional gains and losses that are included in other income, net, for our consolidated entities and in equity earnings for our JVs.

We may utilize cross-currency swaps that exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican fixed interest rates for U.S. fixed interest rates. The impacts of these cross-currency swaps are offset in OCI and are reclassified from AOCI into earnings through other income, net, and interest expense as settlements occur.

Certain of our Mexican pipelines (namely Los Ramones I and San Fernando at IEnova Pipelines and Los Ramones Norte at TAG Pipelines) generate revenue based on tariffs that are set by government agencies in Mexico, with contracts denominated in Mexican pesos that are indexed to the U.S. dollar, adjusted annually for inflation and fluctuation in the exchange rate. The resultant gains and losses from remeasuring the local currency amounts into U.S. dollars and the offsetting settlement of foreign currency forwards and swaps related to these contracts are included in revenues: energy-related businesses or equity earnings.

Income statement activities at our foreign operations and their JVs are also impacted by transactional gains and losses, a summary of which is shown in the table below:

TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION EFFECTS

(Dollars in millions)

Foreign Currency Exchange Rate and Inflation Impacts on Income Taxes and Related Hedging Activity

Our Mexican subsidiaries have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that are affected by Mexican currency exchange rate movements for Mexican income tax purposes. They also have significant deferred income tax assets and liabilities denominated in the Mexican peso that must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation may expose us to fluctuations in income tax expense, other income, net, and equity earnings. We may use foreign currency derivatives as a means to help manage exposure to the currency exchange rate on our monetary assets and liabilities, and this derivative activity impacts other income, net. However, we generally do not hedge our deferred income tax assets and liabilities, which makes us susceptible to volatility in income tax expense caused by exchange rate fluctuations and inflation.

We discuss herein SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2023 compared to the year ended December 31, 2022. For a discussion of SDG&E’s results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to “Part II – Item 7. MD&A – Results of Operations” in our 2022 annual report on Form 10-K filed with the SEC on February 28, 2023.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

(Dollars in millions)

In 2023 compared to 2022, the increase in SDG&E’s earnings of $21 million (2%) was primarily due to:

• $40 million higher CPUC base operating margin, net of operating expenses and $24 million from lower authorized cost of capital
• $21 million higher electric transmission margin
• $18 million higher net regulatory interest income

Offset by:

• $30 million higher net interest expense
• $15 million lower income tax benefit from the resolution of prior year income tax items
• $5 million Wildfire Fund accelerated amortization in 2023

SIGNIFICANT CHANGES IN REVENUES AND COSTS

Electric Revenues and Cost of Electric Fuel and Purchased Power

In 2023 compared to 2022, SDG&E’s electric revenues decreased by $446 million (9%) to $4.3 billion primarily due to:

• $549 million lower cost of electric fuel and purchased power, which we discuss below
• $197 million in 2023 from the recognition of investment tax credits from standalone energy storage projects, which are offset in income tax benefit (expense)

Offset by:

• $97 million higher revenues from incremental and balanced capital projects
• $92 million higher revenues associated with refundable programs, which are fully offset in O&M
• $50 million higher revenues from transmission operations
• $45 million higher CPUC-authorized revenues

In 2023 compared to 2022, SDG&E’s cost of electric fuel and purchased power decreased by $549 million to $445 million primarily due to:

• $396 million lower purchased power from the California ISO due to lower customer demand from departing load now served by CCAs and lower market prices
• $170 million lower purchased power due to higher excess capacity sales to third parties
• $157 million lower utility-owned generation costs
• $65 million higher realized gains on derivative contracts for fixed-price natural gas, which are entered into to hedge the cost of electric fuel, and GHG allowances

Offset by:

• $259 million lower sales to the California ISO due to lower market prices

Natural Gas Revenues and Cost of Natural Gas

SDG&E’s average cost of natural gas per thousand cubic feet was $11.05 in 2023 and $8.01 in 2022. The average cost of natural gas sold at SDG&E is impacted by market prices, as well as transportation, tariff and other charges.

In 2023 compared to 2022, SDG&E’s natural gas revenues increased by $205 million (20%) to $1.2 billion primarily due to:

• $169 million increase in cost of natural gas sold, which we discuss below
• $32 million higher revenues from incremental and balanced capital projects
• $29 million higher revenues associated with refundable programs, which are fully offset in O&M
• $12 million higher CPUC-authorized revenues

Offset by:

• $44 million lower regulatory revenues in 2023 from the election to change the tax accounting method under Revenue Procedure 2023-15, which are offset in income tax benefit (expense)

In 2023 compared to 2022, SDG&E’s cost of natural gas increased by $169 million (47%) to $532 million primarily due to:

• $146 million higher average natural gas prices
• $23 million higher volumes driven by weather

Operation and Maintenance

In 2023 compared to 2022, SDG&E’s O&M increased by $169 million (10%) to $1.8 billion primarily due to:

• $121 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue
• $48 million higher non-refundable operating costs, including Wildfire Fund accelerated amortization in 2023

Other Income, Net

In 2023 compared to 2022, SDG&E’s other income, net, increased by $5 million (5%) to $97 million primarily due to:

• $24 million higher net interest income on regulatory balancing accounts due to higher commercial paper rates

Offset by:

• $8 million higher non-service components of net periodic benefit cost

Interest Expense

In 2023 compared to 2022, SDG&E’s interest expense increased by $48 million (11%) to $497 million primarily from higher debt balances from debt issuances and higher interest rates.

Income Taxes

INCOME TAX (BENEFIT) EXPENSE AND EFFECTIVE INCOME TAX RATES

(Dollars in millions)

2023 Form 10-K | 75

SDG&E had an income tax benefit in 2023 compared to income tax expense in 2022 primarily due to lower pretax income and the following tax matters.

Under the IRA, in 2023, the scope of projects eligible for investment tax credits was expanded to include standalone energy storage projects. The IRA also provided an election that permits investment tax credits related to standalone energy storage projects to be returned to utility customers over a period that is shorter than the life of the applicable asset. Under this election, SDG&E recorded an income tax benefit of $142 million for these investment tax credits, offset by a regulatory liability, which reduced SDG&E’s ETR in 2023.

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. SDG&E intends to elect this change in tax accounting method in Sempra’s consolidated 2023 income tax return filing and has recorded an estimated income tax benefit of $34 million in 2023. SDG&E recorded an associated regulatory liability for the portion of these benefits that will be flowed through to customers in the future.

We discuss herein SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2023 compared to the year ended December 31, 2022. For a discussion of SoCalGas’ results of operations and significant changes in earnings, revenues and costs for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to “Part II – Item 7. MD&A – Results of Operations” in our 2022 annual report on Form 10-K filed with the SEC on February 28, 2023.

RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

(Dollars in millions)

In 2023 compared to 2022, the increase in SoCalGas’ earnings of $212 million (35%) was primarily due to:

• $199 million charge in 2022 relating to litigation and regulatory matters pertaining to the Leak
• $36 million higher income tax benefits primarily from flow-through items, which includes $25 million related to income tax benefits in 2023 for previously unrecognized income tax benefits pertaining to gas repairs expenditures
• $21 million higher net regulatory interest income
• $13 million higher regulatory awards approved by the CPUC
• $10 million in penalties in 2022 related to energy efficiency and advocacy OSCs

Offset by:

• $60 million higher net interest expense
• $8 million lower CPUC base operating margin, net of operating expenses and $22 million from lower authorized cost of capital

SIGNIFICANT CHANGES IN REVENUES AND COSTS

Natural Gas Revenues and Cost of Natural Gas

SoCalGas’ average cost of natural gas per thousand cubic feet was $10.47 in 2023 and $7.48 in 2022. The average cost of natural gas sold at SoCalGas is impacted by market prices, as well as transportation and other charges.

In 2023 compared to 2022, SoCalGas’ natural gas revenues increased by $1.4 billion (21%) to $8.3 billion primarily due to:

• $1.0 billion increase in cost of natural gas sold, which we discuss below
• $385 million higher revenues associated with refundable programs, which are fully offset in O&M
• $98 million higher CPUC-authorized revenues
• $38 million higher non-service components of net periodic benefit cost, which fully offsets in other expense, net
• $19 million higher franchise fee revenues
• $18 million higher regulatory awards approved by the CPUC

Offset by:

• $127 million lower regulatory revenues in 2023 from the election to change the tax accounting method under Revenue Procedure 2023-15, which are offset in income tax benefit (expense)
• $26 million lower regulatory revenues in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures, which are offset in income tax benefit (expense)

In 2023 compared to 2022, SoCalGas’ cost of natural gas increased by $1.0 billion (46%) to $3.3 billion primarily due to:

• $931 million higher average natural gas prices
• $100 million higher volumes driven by weather

Operation and Maintenance

In 2023 compared to 2022, SoCalGas’ O&M increased by $419 million (17%) to $2.8 billion primarily due to:

• $385 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue
• $34 million higher non-refundable operating costs

Aliso Canyon Litigation and Regulatory Matters

In 2022, SoCalGas recorded charges of $259 million relating to litigation and regulatory matters pertaining to the Leak.

Other Expense, Net

In 2023 compared to 2022, SoCalGas’ other expense, net, decreased by $4 million to $4 million primarily due to:

• $29 million higher net interest income on regulatory balancing accounts primarily due to higher commercial paper rates
• $10 million in penalties in 2022 related to energy efficiency and advocacy OSCs

Offset by:

• $38 million higher non-service components of net periodic benefit cost

Interest Expense

In 2023 compared to 2022, SoCalGas’ interest expense increased by $87 million (44%) to $285 million primarily from higher debt balances from debt issuances and higher interest rates.

Income Taxes

INCOME TAX (BENEFIT) EXPENSE AND EFFECTIVE INCOME TAX RATES

(Dollars in millions)

2023 Form 10-K | 77

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor method of accounting for gas repairs expenditures. SoCalGas intends to elect this change in tax accounting method in Sempra’s consolidated 2023 income tax return filing and has recorded an estimated income tax benefit of $97 million in 2023. Additionally, SoCalGas updated its assessment of prior years’ unrecognized income tax benefits and recorded an income tax benefit of $43 million in 2023 for previously unrecognized income tax benefits pertaining to gas repairs expenditures. SoCalGas recorded associated regulatory liabilities for the portion of these benefits that will be flowed through to customers in the future.

SoCalGas’ had an income tax benefit in 2023 compared to income tax expense in 2022 primarily due to:

• higher income tax benefits from flow-through items, including $97 million income tax benefit for the election to change the tax accounting method under Revenue Procedure 2023-15
• $43 million income tax benefit in 2023 from the recognition of previously unrecognized income tax benefits pertaining to gas repairs expenditures
• lower pretax income in 2023 compared to 2022 (before charges in 2022 relating to litigation and regulatory matters pertaining to the Leak)

Offset by:

• $60 million income tax benefit in 2022 associated with charges relating to litigation and regulatory matters pertaining to the Leak

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW

Sempra

Liquidity

We expect to meet our cash requirements through cash flows from operations, unrestricted cash and cash equivalents, borrowings under or supported by our credit facilities, other incurrences of debt which may include issuing debt securities and obtaining term loans, and other financing transactions which may include issuing equity securities, distributions from our equity method investments, project financing and funding from NCI owners. We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:

• finance capital expenditures
• repay debt
• fund dividends
• fund contractual and other obligations and otherwise meet liquidity requirements
• fund capital contribution requirements
• fund new business or asset acquisitions or start-ups

Sempra, SDG&E and SoCalGas currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow or otherwise raise money at market rates from commercial banks, under existing revolving credit facilities, through public offerings of debt or equity securities, or through private placements of debt supported by our revolving credit facilities in the case of commercial paper. However, our ability to access these markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if economic conditions worsen or disruptions to or volatility in these markets increase. Debt funding has become less attractive due to the recent rise in both short-term and long-term interest rates. In addition, our financing activities and actions by credit rating agencies, as well as many other factors, could negatively affect the availability and cost of both short-term and long-term debt and equity financing. Also, cash flows from operations may be impacted by the timing of commencement and completion of, and potentially cost overruns for, large projects and other material events, such as the settlement of material litigation. If cash flows from operations were to be significantly reduced or we were unable to borrow or obtain other financing under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety/reliability) and investments in new businesses. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our goal to maintain our investment-grade credit ratings.

Common Stock Offering and Forward Sale Agreements

As we discuss in Note 14 of the Notes to Consolidated Financial Statements, our offering of Sempra common stock completed in November 2023 provided initial net proceeds of $144 million upon the underwriters’ partial exercise of their over-allotment option to purchase additional shares of our common stock. We did not initially receive any proceeds from the sale of our common stock pursuant to the forward sale agreements entered into in connection with the offering. The forward sale agreements permit us to elect, subject to certain conditions, physical settlement, cash settlement or net share settlement for all or a portion of our obligations under the agreements. We expect to settle the forward sale agreements entirely by delivery of shares of our common stock under physical settlement in exchange for cash proceeds in one or more settlements no later than December 31, 2024, which is the final settlement date under the agreements. As of February 27, 2024, at the initial forward sale price of $68.845 per share, we expect that the net proceeds from full physical settlement of the forward sale agreements would be approximately $1.2 billion (net of underwriting discounts, but before deducting equity issuance costs, and subject to certain adjustments pursuant to the forward sale agreements). If we were to elect cash settlement or net share settlement instead of physical settlement, the amount of cash proceeds we receive upon settlement would be less, perhaps substantially, or we may not receive any cash proceeds or we may deliver cash (in an amount that could be significant) or shares of our common stock to the forward purchasers under the forward sale agreements.

We used the initial net proceeds from this offering, and we expect to use any net proceeds from the sale of shares of our common stock pursuant to the forward sale agreements, to fund working capital and for other general corporate purposes, including to partly finance our long-term capital plan and to repay commercial paper and potentially other indebtedness.

Available Funds

Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each have five-year credit agreements expiring in 2028 and Sempra Infrastructure has four committed lines of credit expiring on various dates from 2025 through 2030, and an uncommitted revolving credit facility expiring in 2024.

AVAILABLE FUNDS AT DECEMBER 31, 2023

(Dollars in millions)

(1) Amounts at Sempra include $124 held in non-U.S. jurisdictions. We discuss repatriation in Note 8 of the Notes to Consolidated Financial Statements.

(2) Available unused credit is the total available on committed and uncommitted lines of credit that we discuss in Note 7 of the Notes to Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding and any letters of credit outstanding as a reduction to the available unused credit.

Short-Term Borrowings

We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures, acquisitions or start-ups. SDG&E and SoCalGas use short-term debt primarily to meet working capital needs or to help fund event-specific costs. Commercial paper and lines of credit were our primary sources of short-term debt funding in 2023.

We discuss our short-term debt activities in Note 7 of the Notes to Consolidated Financial Statements and below in “Sources and Uses of Cash.”

The following table shows selected statistics for our commercial paper borrowings.

COMMERCIAL PAPER STATISTICS

(Dollars in millions)

2023 Form 10-K | 79

Long-Term Debt Activities

Significant issuances of and payments on long-term debt in 2023 included the following:

(Dollars in millions)

At December 31, 2023, Sempra expects to make interest payments on long-term debt totaling $19.4 billion, of which $1.2 billion is expected to be paid in 2024 and $18.2 billion is expected to be paid in subsequent years through 2079. At December 31, 2023, SDG&E expects to make interest payments on long-term debt totaling $6.0 billion, of which $340 million is expected to be paid in 2024 and $5.7 billion is expected to be paid in subsequent years through 2053. At December 31, 2023, SoCalGas expects to make interest payments on long-term debt totaling $4.7 billion, of which $278 million is expected to be paid in 2024 and $4.5 billion is expected to be paid in subsequent years through 2053. We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. We calculate expected interest payments for variable-rate obligations based on forecasted rates in effect at December 31, 2023.

We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, and maturities in Note 7 of the Notes to Consolidated Financial Statements.

Credit Ratings

The credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in 2023.

CREDIT RATINGS AT DECEMBER 31, 2023

A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in the imposition of financial or other burdensome covenants or a requirement for collateral to be posted in the case of certain financing arrangements and may materially and adversely affect the market prices of their equity and debt securities, the rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra, SDG&E, SoCalGas and Sempra’s other subsidiaries to issue debt securities, to borrow under credit facilities and to raise certain other types of financing. We provide additional information about our credit ratings at Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors.”

Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A+ and A at Moody’s, S&P and Fitch, respectively, at December 31, 2023.

Sempra, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit that may be impacted by each borrower’s credit rating. For example, assuming a one-notch downgrade:

• If Sempra were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 bps. The commitment fee on available unused credit would also increase 5 bps.
• If SDG&E were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 5 bps.
• If SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 2.5 bps.

Sempra’s, SDG&E’s and SoCalGas’ credit ratings also may affect their respective credit limits related to derivative instruments, as we discuss in Note 11 of the Notes to Consolidated Financial Statements.

Loans to/from Affiliates

At December 31, 2023, Sempra had $312 million in loans due to unconsolidated affiliates.

Postretirement Benefits

Sempra, SDG&E and SoCalGas have significant investments in several trusts to provide for future payments of pensions and PBOP. The trusts’ ability to make ongoing required benefit payments has not been materially adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, changes in asset values or other factors in future periods (such as changes to discount rates, assumed rates of return, mortality tables and regulations) may impact funding requirements for pension and PBOP plans. Additionally, contributions to our plans are based on our funding policy, which generally limits payments from exceeding plan assets of 110% of the projected benefit obligation, which are subject to maximum income tax deduction limitations. Sempra, SDG&E and SoCalGas expect to contribute $265 million, $37 million and $174 million, respectively, to pension and PBOP plans in 2024 and $1.8 billion, $564 million and $983 million, respectively, in the nine years thereafter. At SDG&E and SoCalGas, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and our expected contributions to those plans in Note 9 of the Notes to Consolidated Financial Statements.

Inflation Reduction Act of 2022

The IRA was signed into law in August 2022. The IRA includes tax credits and other incentives for energy and climate initiatives and introduces a 15% corporate alternative minimum tax on adjusted financial statement income for tax years beginning after December 31, 2022. We do not currently expect the IRA to have a material adverse impact on Sempra’s, SDG&E’s or SoCalGas’ results of operations, financial condition and/or cash flows. We will continue to assess the impacts of the IRA on Sempra, SDG&E and SoCalGas as the U.S. Department of the Treasury and the IRS issue guidance on tax implementation, and the EPA and DOE issue guidance on energy and climate initiatives.

Minimum Tax Directive

The Organization for Economic Cooperation and Development has introduced a framework to implement a global minimum corporate tax of 15%, referred to as the “minimum tax directive.” Many aspects of the minimum tax directive will become effective beginning in 2024. While it is uncertain whether the U.S. will enact legislation to adopt the minimum tax directive, other countries are in the process of introducing and enacting legislation to implement the minimum tax directive. We do not currently expect the minimum tax directive to have a material effect on Sempra’s, SDG&E’s or SoCalGas’ results of operations, financial condition and/or cash flows.

Sempra California

SDG&E’s and SoCalGas’ operations have historically provided relatively stable earnings and liquidity. Their future performance and liquidity will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by legislatures, litigation and the changing energy marketplace, as well as other matters described in this report. SDG&E and SoCalGas expect that the available unused funds from their credit facilities described above, which also supports their commercial paper programs, cash flows from operations, and other incurrences of debt including issuing debt securities and obtaining term loans will continue to be adequate to fund their respective current operations and planned capital expenditures. SDG&E and SoCalGas manage their capital structures and pay dividends when appropriate and as approved by their respective boards of directors.

The impact and duration of suspending collections processes during the COVID-19 pandemic, the implementation of customer assistance programs, and higher 2023 winter season customer billings, have resulted in certain SDG&E and SoCalGas customers exhibiting slower payment and higher levels of nonpayment than has been the case historically. This in turn has resulted in an increase in provisions for expected credit losses in the year ended December 31, 2023 for both companies, even as collections processes resume and past due payments potentially begin increasing. SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to Accounts Receivable – Trade that are probable of recovery in regulatory accounts. Although SDG&E and SoCalGas have regulatory mechanisms to recover credit losses, delay in payments by customers impact the timing of cash flows.

As we discuss in Note 4 of the Notes to Consolidated Financial Statements, changes in regulatory balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over- and undercollected status, may have a significant impact on cash flows. These changes generally represent the difference between when costs are incurred and when they are ultimately recovered or refunded in rates through billings to customers.

SDG&E

Wildfire Fund

The carrying value of SDG&E’s Wildfire Fund asset totaled $297 million at December 31, 2023. We describe the Wildfire Legislation and SDG&E’s commitment to make annual shareholder contributions to the Wildfire Fund through 2028 in Note 1 of the Notes to Consolidated Financial Statements.

SDG&E is exposed to the risk that the participating California electric IOUs may incur third-party wildfire costs for which they will seek recovery from the Wildfire Fund with respect to wildfires that have occurred since enactment of the Wildfire Legislation in July 2019. In such a situation, SDG&E may recognize a reduction of its Wildfire Fund asset and record accelerated amortization against earnings when available coverage is reduced due to recoverable claims from any of the participating IOUs, as was the case in 2023 after PG&E indicated that it will seek reimbursement from the Wildfire Fund for losses associated with the Dixie Fire, which burned from July 2021 through October 2021 and was reported to be the largest single wildfire (measured by acres burned) in California history. If any California electric IOU’s equipment is determined to be a cause of a fire, it could have a material adverse effect on SDG&E’s and Sempra’s financial condition and results of operations up to the carrying value of our Wildfire Fund asset, with additional potential material exposure if SDG&E’s equipment is determined to be a cause of a fire. In addition, the Wildfire Fund could be completely exhausted due to fires in the other California electric IOUs’ service territories, by fires in SDG&E’s service territory or by a combination thereof. In the event that the Wildfire Fund is materially diminished, exhausted or terminated, SDG&E will lose the protection afforded by the Wildfire Fund, and as a consequence, a fire in SDG&E’s service territory could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Wildfire Mitigation Cost Recovery Mechanism

In October 2023, SDG&E submitted a separate request to the CPUC in its 2024 GRC describing $2.2 billion in costs to implement its wildfire mitigation plans from 2019 through 2022, and seeking review and recovery of the incremental wildfire mitigation plan costs incurred during that period, totaling $1.5 billion. SDG&E expects to receive a proposed decision on this request in late 2024. In February 2024, the CPUC approved an interim cost recovery mechanism that would permit SDG&E to recover in rates $194 million of its wildfire mitigation plan regulatory account balance in 2024 and, if a recovery mechanism is not in place by January 1, 2025, an additional $96 million in 2025. Such recovery of SDG&E’s wildfire mitigation plan regulatory account balance will be subject to reasonableness review. SDG&E also expects to submit a separate request for review and recovery of its 2023 wildfire mitigation plan costs in late 2024.

SONGS Decommissioning

SDG&E has significant investments in the SONGS NDT to provide for future payments of nuclear decommissioning. The NDT’s ability to make ongoing required payments has not been materially or adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, asset values could be materially and adversely affected by future activity in the equity and fixed income markets, and changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions to the estimated total cost associated with retiring the assets. Funding requirements are generally recoverable in rates. We discuss SDG&E’s NDT and its expected SONGS decommissioning payments in Note 15 of the Notes to Consolidated Financial Statements.

Off-Balance Sheet Arrangements

SDG&E has entered into PPAs and tolling agreements that are variable interests in unconsolidated entities. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.

SoCalGas

Aliso Canyon Natural Gas Storage Facility Gas Leak

From October 23, 2015 through February 11, 2016, SoCalGas experienced the Leak, which we discuss in Note 16 of the Notes to Consolidated Financial Statements and in “Part I – Item 1A. Risk Factors.”

Accounting and Other Impacts. At December 31, 2023, $31 million is accrued in Reserve for Aliso Canyon Costs and $2 million is accrued in Deferred Credits and Other on SoCalGas’ and Sempra’s Consolidated Balance Sheets. These accruals do not include any amounts in excess of what has been reasonably estimated to resolve certain matters that we describe in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak – Litigation” in Note 16 of the Notes to Consolidated Financial Statements, nor any amounts that may be necessary to resolve threatened litigation, other potential litigation or other costs. We are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued, which could be significant and could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.

Natural Gas Storage Operations and Reliability. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter and peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important component of SoCalGas’ delivery system. In February 2017, the CPUC opened proceeding SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including analyzing alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated.

At December 31, 2023, the Aliso Canyon natural gas storage facility had a net book value of $1.0 billion. If the Aliso Canyon natural gas storage facility were to be permanently closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we may record an impairment of the facility, which could be material, incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized.

Franchise Agreement

SoCalGas’ Los Angeles County franchise initially expired in June 2023 and the subsequent extension expired in December 2023. SoCalGas is in the process of negotiating a new agreement with Los Angeles County. SoCalGas is operating and expects to continue to operate under the terms and provisions of the expired franchise until a new agreement is reached and does not anticipate disruption of service to customers in unincorporated Los Angeles County while negotiations continue.

Sempra Texas Utilities

Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the event that Oncor fails to meet its capital requirements, access sufficient capital, or raise capital on favorable terms to finance its ongoing needs, we may elect to make additional capital contributions to Oncor (as our commitments to the PUCT prohibit us from making loans to Oncor), which could be substantial and reduce the cash available to us for other purposes, increase our indebtedness and ultimately materially adversely affect our results of operations, financial condition, cash flows and/or prospects. Oncor’s ability to make distributions may be limited by factors such as its credit ratings, regulatory capital requirements, increases in its capital plan, debt-to-equity ratio approved by the PUCT and other restrictions and considerations. In addition, Oncor will not make distributions if a majority of Oncor’s independent directors or any minority member director determines it is in the best interests of Oncor to retain such amounts to meet expected future requirements.

Rates and Cost Recovery

The PUCT issued a final order in Oncor’s most recent comprehensive base rate proceeding in April 2023, and rates implementing that order went into effect on May 1, 2023. In June 2023, the PUCT issued an order on rehearing in response to the motions for rehearing filed by Oncor and certain intervenor parties in the proceeding. The order on rehearing made certain technical and typographical corrections to the final order but otherwise affirmed the material provisions of the final order and did not require modification of the rates that went into effect on May 1, 2023. In September 2023, Oncor filed an appeal in Travis County District Court seeking judicial review of certain rate base disallowances and related expense effects of those disallowances in the PUCT’s order on rehearing. On February 22, 2024, the court dismissed the appeal for lack of jurisdiction. Oncor is evaluating whether to appeal that ruling.

Off-Balance Sheet Arrangement

Our investment in Oncor Holdings is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.

Sempra Infrastructure

Sempra Infrastructure expects to fund capital expenditures, investments and operations in part with available funds, including existing credit facilities, and cash flows from operations of the Sempra Infrastructure businesses. We expect Sempra Infrastructure will require additional funding for the development and expansion of its portfolio of projects, which may be financed through a combination of funding from the parent and NCI owners, bank financing, issuances of debt, project financing, partnering in JVs and asset sales.

At December 31, 2023, Sempra, KKR Pinnacle and ADIA directly or indirectly own a 70%, 20%, and 10% interest, respectively, in SI Partners, and KKR Denali, an affiliate of ConocoPhillips and TotalEnergies SE each own a 60%, 30% and 16.6% interest, respectively, in three separate SI Partners subsidiaries. In 2023 and 2022, Sempra Infrastructure distributed $730 million and $237 million, respectively, to its NCI owners, and NCI owners contributed $1,770 million and $31 million, respectively, to Sempra Infrastructure.

Sempra Infrastructure is in various stages of development or construction on natural gas liquefaction projects, pipeline and terminal projects, and renewable generation and sequestration projects, which we describe below. The successful development and/or construction of these projects is subject to numerous risks and uncertainties.

With respect to projects in development, these risks and uncertainties include, as applicable depending on the project, any failure to:

• secure binding customer commitments
• identify suitable project and equity partners
• obtain sufficient financing
• reach agreement with project partners or other applicable parties to proceed
• obtain, modify, and/or maintain permits and regulatory approvals, including LNG export applications to non-FTA countries in light of the current Administration’s temporary pause of such approvals while the DOE reviews the economic and environmental analyses it uses to evaluate such applications
• negotiate, complete and maintain suitable commercial agreements, which may include EPC, tolling, equity acquisition, governance, LNG sales, gas supply and transportation contracts
• reach a positive final investment decision

With respect to projects under construction, these risks and uncertainties include, in addition to the risks described above as applicable to each project, construction delays and cost overruns.

An unfavorable outcome with respect to any of these factors could have a material adverse effect on (i) the development and construction of the applicable project, including a potential impairment of all or a substantial portion of the capital costs invested in the project to date, which could be material, and (ii) for any project that has reached a positive final investment decision, Sempra’s results of operations, financial condition, cash flows and/or prospects. For a further discussion of these risks, see “Part I – Item 1A. Risk Factors.”

The descriptions below discuss several HOAs, MOUs and other non-binding development agreements with respect to Sempra Infrastructure’s various development projects. These arrangements do not commit any party to enter into definitive agreements or otherwise participate in the applicable project, and the ultimate participation by the parties remains subject to negotiation and finalization of definitive agreements, among other factors.

LNG

Cameron LNG Phase 2 Project. Cameron LNG JV is developing a proposed expansion project that would add one liquefaction train with an expected maximum production capacity of approximately 6.75 Mtpa and would increase the production capacity of the existing three trains at the Cameron LNG Phase 1 facility by up to approximately 1 Mtpa through debottlenecking activities. The Cameron LNG JV site can accommodate additional trains beyond the proposed Cameron LNG Phase 2 project.

Cameron LNG JV previously received major permits and FTA and non-FTA approvals associated with the potential expansion that included up to two additional liquefaction trains and up to two additional full containment LNG storage tanks. The non-FTA approval for the proposed Cameron LNG Phase 2 project includes, among other things, a May 2026 deadline to commence commercial exports, for which we expect to request an extension. In March 2023, the FERC approved Cameron LNG JV’s request to amend the permits to allow the use of electric drives, instead of gas turbine drives, which would reduce GHG emissions. The amendment also allows the design to be changed from a two-train gas turbine expansion to a one-train electric drive expansion along with other design enhancements that, together, we expect would result in a more cost-effective and efficient facility, while also reducing GHG emissions.

Sempra Infrastructure and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha, have entered into a non-binding HOA for the potential development of the Cameron LNG Phase 2 project. The non-binding HOA provides a commercial framework for the proposed project, including the contemplated allocation to SI Partners of 50.2% of the fourth train production capacity and 25% of the debottlenecking capacity from the project under tolling agreements. The non-binding HOA contemplates the remaining capacity to be allocated equally to the existing Cameron LNG Phase 1 facility customers. Sempra Infrastructure plans to sell the LNG corresponding to its allocated capacity from the proposed Cameron LNG Phase 2 project under long-term SPAs prior to making a final investment decision.

In July 2023, following completion of front-end engineering design contracts with two parties, Cameron LNG JV informed Bechtel that it had been selected to perform additional value engineering work on the proposed Cameron LNG Phase 2 project. After completion of the value engineering work, in January 2024, Cameron LNG JV terminated further work under the applicable agreement with Bechtel. Cameron LNG JV is preparing to re-bid the EPC work for the proposed Cameron LNG Phase 2 project to help optimize the project’s costs and schedule. We expect this work will continue through the end of 2024 and to be in a position to make a final investment decision in the first half of 2025 and complete all related financing and permitting activities necessary to align our authorizations with the proposed schedule for the project.

In December 2023, Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, and Cameron LNG JV signed a new electricity service agreement (and related ancillary agreements) for the supply to Cameron LNG JV of up to 950 MW of renewable power from new renewable resources in Louisiana. The agreement is subject to approval by the Louisiana Public Service Commission and existing project lenders.

Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is subject to certain restrictions and conditions under the JV project financing agreements, including among others, scope restrictions on expansion of the project unless appropriate prior consent is obtained from the existing project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the members, including with respect to the equity investment obligation of each member.

ECA LNG Phase 1 Project. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility. SI Partners owns an 83.4% interest in ECA LNG Phase 1, and an affiliate of TotalEnergies SE owns the remaining 16.6% interest. At December 31, 2023, Sempra holds an indirect interest in the ECA LNG Phase 1 project of 58.4%.

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the ECA LNG Phase 1 project. ECA LNG Phase 1 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.

We have an EPC contract with TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of Technip Energies N.V., to construct the ECA LNG Phase 1 project. We estimate the total price of the EPC contract to be approximately $1.5 billion, with capital expenditures approximating $2 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the ECA LNG Phase 1 project to commence commercial operations in the summer of 2025.

ECA LNG Phase 1 has a five-year loan agreement with a syndicate of seven external lenders that matures in December 2025 for an aggregate principal amount of up to $1.3 billion, of which $832 million was outstanding at December 31, 2023. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project.

With respect to the ECA LNG Phase 1 and Phase 2 projects, recent and proposed changes to the law in Mexico and the unfavorable resolution of land disputes and permit challenges, in each case that we discuss in Note 16 of the Notes to Consolidated Financial Statements, could have a material adverse effect on the development and construction of these projects.

ECA LNG Phase 2 Project. Sempra Infrastructure is developing a second, large-scale natural gas liquefaction project at the site of its existing ECA Regas Facility. We expect the proposed ECA LNG Phase 2 project to be comprised of two trains and one LNG storage tank and produce approximately 12 Mtpa of export capacity. We expect that construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has long-term regasification contracts for 100% of the regasification facility’s capacity through 2028. This makes the decisions on whether, when and how to pursue the proposed ECA LNG Phase 2 project dependent in part on whether the investment in a large-scale liquefaction facility would, over the long term, be more beneficial financially than continuing to supply regasification services under our existing contracts.

We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the proposed ECA LNG Phase 2 project.

We have non-binding MOUs and/or HOAs with Mitsui & Co., Ltd., an affiliate of TotalEnergies SE, and ConocoPhillips that provide a framework for their potential offtake of LNG from the proposed ECA LNG Phase 2 project and potential acquisition of an equity interest in ECA LNG Phase 2.

PA LNG Phase 1 Project. Since making a positive final investment decision in March 2023, Sempra Infrastructure is constructing a natural gas liquefaction project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. The PA LNG Phase 1 project will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa.

Sempra Infrastructure has received authorizations from the DOE that permit the LNG to be produced from the PA LNG Phase 1 project to be exported to all current and future FTA and non-FTA countries. In April 2019, the FERC approved the siting, construction and operation of the PA LNG Phase 1 project. In June 2023, Port Arthur LNG requested authorization from the FERC to increase its work force and implement a 24-hours-per-day construction schedule to further enhance construction efficiency while reducing temporal impacts to the community and environment in the vicinity of the project. If approved, the authorization would provide the EPC contractor with more optionality to meet or exceed the project’s construction schedule, subject to the timing of FERC approval. The FERC has published a schedule that anticipates the issuance of an environmental assessment for the project in March 2024.

The PA LNG Phase 1 project holds two Clean Air Act, Prevention of Significant Deterioration permits issued by the TCEQ, which we refer to as the “2016 Permit” and the “2022 Permit.” The 2022 Permit also governs emissions for the proposed PA LNG Phase 2 project.

In November 2023, a panel of the U.S. Court of Appeals for the Fifth Circuit issued a decision to vacate and remand the 2022 Permit to the TCEQ for additional explanation of the agency’s permit decision. In February 2024, the court withdrew its opinion pending a determination by the Supreme Court of Texas as to the proper standard to be applied by the TCEQ. The 2022 Permit remains effective during the Supreme Court’s review. The 2016 Permit was not the subject of, and is unaffected by, the court’s decision. Construction of the PA LNG Phase 1 project is proceeding uninterrupted under existing permits, and we do not currently anticipate material impacts to the PA LNG Phase 1 project cost, schedule or expected commercial operations at this stage.

Sempra Infrastructure has definitive SPAs for LNG offtake from the PA LNG Phase 1 project 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 for a 20-year term for approximately 1.4 Mtpa of LNG.
• ORLEN 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.

We have an EPC contract with Bechtel to construct the PA LNG Phase 1 project. In March 2023, we issued a final notice to proceed under the EPC contract, which has an estimated price of approximately $10.7 billion. We estimate the capital expenditures for the PA LNG Phase 1 project will be approximately $13 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the first and second trains of the PA LNG Phase 1 project to commence commercial operations in 2027 and 2028, respectively.

In March 2023, an indirect subsidiary of SI Partners completed the sale of an indirect 30% interest in another SI Partners subsidiary (resulting in an indirect 30% NCI in the PA LNG Phase 1 project) to an affiliate of ConocoPhillips for aggregate cash consideration of $254 million. We used the proceeds from this sale for capital expenditures and other general corporate purposes. In connection with this sale, both SI Partners and ConocoPhillips provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee.

In September 2023, an indirect subsidiary of SI Partners completed the sale of an indirect 60% interest in another SI Partners subsidiary (resulting in an indirect 42% NCI in the PA LNG Phase 1 project) to KKR Denali for aggregate cash consideration of $976 million. We used the proceeds from this sale for capital expenditures and other general corporate purposes.

At December 31, 2023, SI Partners holds a 28% indirect interest and Sempra holds a 19.6% indirect interest in the PA LNG Phase 1 project.

In March 2023, Port Arthur LNG entered into a seven-year term loan facility agreement with a syndicate of lenders for an aggregate principal amount of approximately $6.8 billion and an initial working capital facility agreement for up to $200 million. The facilities mature in March 2030. Proceeds from the loans will be used to finance the cost of construction of the PA LNG Phase 1 project. At December 31, 2023, $258 million of borrowings were outstanding under the term loan facility agreement.

PA LNG Phase 2 Project. Sempra Infrastructure is developing a second phase of the Port Arthur natural gas liquefaction project that we expect will be a similar size to the PA LNG Phase 1 project. We are progressing the development of the proposed PA LNG Phase 2 project, while continuing to evaluate overall opportunities to develop the entirety of the Port Arthur site as well as potential design changes that could reduce GHG emissions, including a facility design utilizing renewable power sourcing and other technological solutions.

In September 2023, the FERC approved the siting, construction and operation of the proposed PA LNG Phase 2 project, including the potential addition of up to two liquefaction trains. In February 2020, Sempra Infrastructure filed an application with the DOE to permit LNG produced from the proposed PA LNG Phase 2 project to be exported to all current and future FTA and non-FTA countries. We do not expect the DOE to act on this application until after the conclusion of the temporary pause on the DOE’s LNG export approvals that we describe above.

As we discuss above, a U.S. federal court previously issued and subsequently withdrew a decision that would have vacated and remanded the 2022 Permit authorizing emissions from the PA LNG Phase 1 and Phase 2 projects to the TCEQ for additional explanation of the agency’s permit decision. The U.S. Court of Appeals for the Fifth Circuit has referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. The 2022 Permit remains effective pending the Supreme Court’s review.

Sempra Infrastructure has entered into a non-binding HOA for the negotiation and potential finalization of a definitive SPA with INEOS for approximately 0.2 Mtpa of LNG offtake from the proposed PA LNG Phase 2 project.

Vista Pacifico LNG Liquefaction Project. Sempra Infrastructure is developing the Vista Pacifico LNG project, a mid-scale natural gas liquefaction export facility proposed to be located in the vicinity of the Port of Topolobampo in Sinaloa, Mexico, under a non-binding development agreement with the CFE that contemplates the negotiation of definitive agreements, including a natural gas supply agreement. The proposed LNG export terminal would be supplied with U.S. natural gas and would use excess natural gas and pipeline capacity on existing pipelines in Mexico with the intent of helping to meet growing demand for natural gas and LNG in the Mexican and Pacific markets.

Sempra Infrastructure received authorization from the DOE to permit the export of U.S.-produced natural gas to Mexico and for LNG produced from the proposed Vista Pacifico LNG facility to be re-exported to all current and future FTA countries and non-FTA countries.

In March 2022, TotalEnergies SE and Sempra Infrastructure entered into a non-binding MOU that contemplates TotalEnergies SE potentially contracting approximately one-third of the long-term export production of the proposed Vista Pacifico LNG project and potentially participating as a minority partner in the project.

Asset and Supply Optimization. As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” Sempra Infrastructure enters into hedging transactions to help mitigate commodity price risk and optimize the value of its LNG, natural gas pipelines and storage, and power-generating assets. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility, which may be material, as the economic offset of these derivatives may not be recorded at fair value.

Off-Balance Sheet Arrangements. Our investment in Cameron LNG JV is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.

In June 2021, Sempra provided a promissory note, which constitutes a guarantee, for the benefit of Cameron LNG JV with a maximum exposure to loss of $165 million. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt, scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA. We discuss this guarantee in Note 6 of the Notes to Consolidated Financial Statements.

In July 2020, Sempra entered into a Support Agreement, which contains a guarantee and represents a variable interest, for the benefit of CFIN with a maximum exposure to loss of $979 million. The guarantee will terminate upon full repayment of the guaranteed debt by 2039, including repayment following an event in which the guaranteed debt is put to Sempra. We discuss this guarantee in Notes 1, 6 and 12 of the Notes to Consolidated Financial Statements.

Energy Networks

Sonora Pipeline. Sempra Infrastructure’s Sonora natural gas pipeline consists of two segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017. Legal challenges raised by some members of the Yaqui tribe living in the Bácum community, which we discuss in Note 16 of the Notes to Consolidated Financial Statements, have prevented Sempra Infrastructure from making repairs to put the pipeline back in service. Such legal challenges were definitively resolved in March 2023 based on the agreement by the CFE and Sempra Infrastructure to re-route the portion of the pipeline that is in the Yaqui territory.

In September 2019, Sempra Infrastructure and the CFE reached an agreement to modify the tariff structure and extend the term of the contract by 10 years. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is back in service.

Sempra Infrastructure and the CFE have agreed to an amendment to their transportation services agreement and to proceed with re-routing a portion of the pipeline, whereby the CFE would pay for the re-routing with a new tariff. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Sempra Infrastructure continues to acquire and pursue the necessary rights-of-way and permits for the re-routed portion of the pipeline.

At December 31, 2023, Sempra Infrastructure had $411 million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if Sempra Infrastructure is unable to re-route a portion of the pipeline and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery, which in each case could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Refined Products Terminals. In May 2022, Sempra Infrastructure substantially completed construction of a terminal for the receipt, storage, and delivery of refined products in Topolobampo, at which time commissioning activities commenced. We expect the Topolobampo terminal will commence commercial operations in the second quarter of 2024.

Sempra Infrastructure is also developing terminals for the receipt, storage, and delivery of refined products in the vicinity of Manzanillo and Ensenada.

Port Arthur Pipeline Louisiana Connector. Sempra Infrastructure has made a positive final investment decision on and begun procurement and engineering activities and rights-of-way acquisition related to the construction of the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana. In April 2019, the FERC approved the siting, construction and operation of the Port Arthur Pipeline Louisiana Connector, which will be used to supply feed gas to the PA LNG Phase 1 project. In July 2023, Sempra Infrastructure filed a limited amendment application with the FERC to implement construction process enhancements and minor modifications to several discrete sections of the Port Arthur Pipeline Louisiana Connector. These modifications are intended to decrease environmental impacts, accommodate landowner routing requests and enhance construction procedures. In February 2024, the FERC issued an environmental assessment for the project. We expect the Port Arthur Pipeline Louisiana Connector to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements. We estimate the capital expenditures for the project will be approximately $1 billion, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates.

Louisiana Storage. Sempra Infrastructure has made a positive final investment decision on and begun procurement and engineering activities related to the construction of 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. In September 2022, the FERC approved the development of the project. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project. We estimate the capital expenditures for the project will be approximately $300 million, including capitalized interest at the project level and project contingency. The actual amount of these capital expenditures may differ substantially from our estimates.

Low Carbon Solutions

Cimarrón Wind. Sempra Infrastructure is developing the Cimarrón Wind project, an approximately 300-MW wind generation facility in Baja California, Mexico. In October 2022, Sempra Infrastructure entered into a 20-year PPA, as amended, with Silicon Valley Power for the long-term supply of renewable energy to the City of Santa Clara, California, which is subject to Sempra Infrastructure reaching a final investment decision. Cimarrón Wind would utilize Sempra Infrastructure’s existing cross-border high voltage transmission line to interconnect and deliver clean energy to the East County substation in San Diego County. We expect to make a final investment decision in the first half of 2024.

Hackberry Carbon Sequestration Project. Sempra Infrastructure is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana. This proposed project under development is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility and the proposed Cameron LNG Phase 2 project. In 2021, Sempra Infrastructure filed an application with the EPA for a Class VI carbon injection well to advance this project.

Sempra Infrastructure, TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation have entered into a Participation Agreement for the development of the proposed Hackberry Carbon Sequestration project. The Participation Agreement contemplates that the combined Cameron LNG Phase 1 facility and proposed Cameron LNG Phase 2 project would potentially serve as the anchor source for the capture and sequestration of carbon dioxide by the proposed project. It also provides the basis for the parties to acquire an equity interest by entering into a JV with Sempra Infrastructure for the Hackberry Carbon Sequestration project. In May 2023, Sempra Infrastructure and Cameron LNG JV entered into a non-binding HOA, which sets forth a framework for further development of the Hackberry Carbon Sequestration project.

Legal and Regulatory Matters

See Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors” for discussions of the following legal and regulatory matters affecting our operations in Mexico:

Energía Costa Azul

• Land Disputes
• Environmental and Social Impact Permits

One or more unfavorable final decisions on these land disputes or environmental and social impact permit challenges could materially adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the site of the ECA Regas Facility and have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

Regulatory and Other Actions by the Mexican Government

• Amendments to Mexico’s Hydrocarbons Law
• Amendments to Mexico’s Electricity Industry Law

Sempra Infrastructure and other parties affected by these amendments to Mexican law have challenged them by filing amparo and other claims, some of which remain pending. An unfavorable decision on one or more of these amparo or other challenges, the impact of the amendments that have become effective (due to unsuccessful amparo challenges or otherwise), or the possibility of future reforms to the energy industry through additional amendments to Mexican laws, regulations or rules (including through amendments to the constitution) may impact our ability to operate our facilities at existing levels or at all, may result in increased costs for Sempra Infrastructure and its customers, may adversely affect our ability to develop new projects, may result in decreased revenues and cash flows, and may negatively impact our ability to recover the carrying values of our investments in Mexico, any of which may have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.

SOURCES AND USES OF CASH

We discuss herein our sources and uses of cash for the year ended December 31, 2023 compared to the year ended December 31, 2022. For a discussion of our sources and uses of cash for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to “Part II – Item 7. MD&A – Sources and Uses of Cash” in our 2022 annual report on Form 10-K filed with the SEC on February 28, 2023.

The following tables include only significant changes in cash flow activities for each of our Registrants.

CASH FLOWS FROM OPERATING ACTIVITIES

(Dollars in millions)

CASH FLOWS FROM INVESTING ACTIVITIES

(Dollars in millions)

2023 Form 10-K | 90

CASH FLOWS FROM FINANCING ACTIVITIES

(Dollars in millions)

Expenditures for PP&E

We invest the majority of our capital expenditures in Sempra California, primarily for transmission and distribution improvements, including pipeline and wildfire safety. The following table summarizes by segment capital expenditures for the last three years.

EXPENDITURES FOR PP&E

(Dollars in millions)

(1) Includes expenditures for PP&E of $2,540, $2,473, and $2,220 at SDG&E and $2,020, $1,993, and $1,984 at SoCalGas for 2023, 2022, and 2021, respectively.

Expenditures for Investments and Acquisitions

The following table summarizes by segment our investments in entities that we account for under the equity method, as well as asset acquisitions.

EXPENDITURES FOR INVESTMENTS AND ACQUISITIONS

(Dollars in millions)

2023 Form 10-K | 91

Future Capital Expenditures and Investments

The amounts and timing of capital expenditures and certain investments are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC, the FERC and the PUCT, and various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors.” In 2024, we expect to make capital expenditures and investments of approximately $9.2 billion, as summarized by segment in the following table.

(Dollars in millions)

(1) Includes future capital expenditures of $2,498 and $2,280 at SDG&E and SoCalGas, respectively.

We expect the majority of our capital expenditures and investments in 2024 will relate to transmission and distribution improvements at our regulated public utilities and construction of the PA LNG Phase 1 project, ECA LNG Phase 1 project and natural gas pipelines at Sempra Infrastructure.

From 2024 through 2028, and subject to the factors described below, which could cause these estimates to vary substantially, Sempra expects to make aggregate capital expenditures and investments of approximately $40.4 billion, as follows: $24.1 billion at Sempra California (which includes $12.5 billion at SDG&E and $11.6 billion at SoCalGas), $3.4 billion at Sempra Texas Utilities, and $12.9 billion at Sempra Infrastructure. Capital expenditure amounts include capitalized interest and AFUDC related to debt.

When (i) including Sempra’s proportionate ownership interest in expected capital expenditures at unconsolidated equity method investees while excluding Sempra’s expected capital contributions to those unconsolidated equity method investees and (ii) excluding NCI’s proportionate ownership interest in expected capital expenditures at Sempra and at unconsolidated equity method investees, we expect capital expenditures from 2024 through 2028 to total $48 billion.

Periodically, we review our construction, investment and financing programs and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, and safety and environmental requirements.

Our level of capital expenditures and investments in the next few years may vary substantially and will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in tax law and business opportunities providing desirable rates of return. See “Part I – Item 1A. Risk Factors” for a discussion of these and other factors that could affect future levels of our capital expenditures and investments. We intend to finance our capital expenditures in a manner that will maintain our investment-grade credit ratings and capital structure, but there is no guarantee that we will be able to do so.

Weighted-Average Rate Base

Rate base is the value of assets on which SDG&E and SoCalGas are permitted to earn a specified rate of return in accordance with rules set by regulatory agencies, including the CPUC and the FERC (for SDG&E), which is calculated using a 13-month average in accordance with CPUC methodology as adopted in rate-setting proceedings. The following table summarizes the weighted-average rate base for SDG&E and SoCalGas for the last three years.

WEIGHTED-AVERAGE RATE BASE

(Dollars in millions)

The increase in weighted-average rate base reflects the significant capital investments that SDG&E and SoCalGas have made in transmission and distribution safety and reliability. We expect the weighted-average rate base to continue to increase in 2024 based on our expected capital investments.

Capital Stock Transactions

Sempra

Cash provided by issuances of common and preferred stock was:

• $145 million in 2023
• $4 million in 2022
• $5 million in 2021

Cash used for repurchases of common stock was:

• $32 million in 2023
• $478 million in 2022
• $339 million in 2021

We discuss the issuance and repurchases of common stock in Note 14 of the Notes to Consolidated Financial Statements.

Dividends

Sempra

Sempra paid cash dividends of:

• $1,483 million for common stock and $44 million for preferred stock in 2023
• $1,430 million for common stock and $44 million for preferred stock in 2022
• $1,331 million for common stock and $99 million for preferred stock in 2021

DIVIDENDS PER SHARE ON SEMPRA COMMON STOCK

(As approved by our board of directors)

On February 26, 2024, our board of directors declared a dividend of $0.62 per share on our common stock and a dividend of $24.375 per share on our series C preferred stock, both payable on April 15, 2024.

All declarations of dividends on our common stock and preferred stock are made at the discretion of the board of directors. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend on earnings, cash flows, financial and legal requirements, and other relevant factors at that time. As a result, Sempra’s dividends on common stock and preferred stock declared on a historical basis may not be indicative of future declarations.

SDG&E

In 2023, 2022 and 2021, SDG&E paid common stock dividends to Enova and Enova paid corresponding dividends to Sempra of $100 million, $100 million and $300 million, respectively. SDG&E’s dividends on common stock declared on an annual historical basis may not be indicative of future declarations and could be impacted over the next few years in order for SDG&E to maintain its authorized capital structure while managing its capital investment program.

Enova, a wholly owned subsidiary of Sempra, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova and dividends paid by Enova to Sempra are eliminated in Sempra’s consolidated financial statements.

SoCalGas

In 2023 and 2021, SoCalGas paid common stock dividends to PE and PE paid corresponding dividends to Sempra of $100 million and $75 million, respectively. SoCalGas did not declare or pay common stock dividends in 2022. SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations and could be impacted over the next few years in order for SoCalGas to maintain its authorized capital structure.

PE, a wholly owned subsidiary of Sempra, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to PE and dividends paid by PE to Sempra are eliminated in Sempra’s consolidated financial statements.

Dividend Restrictions

The board of directors for each of Sempra, SDG&E and SoCalGas has the discretion to determine whether to declare and, if declared, the amount of any dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra. At December 31, 2023, based on these regulations, Sempra could have received combined loans and dividends of approximately $442 million from SDG&E and $330 million from SoCalGas. In addition, the terms of Sempra’s series C preferred stock limit Sempra’s ability to declare dividends on its common stock under certain circumstances.

We provide additional information about dividend restrictions in “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements and in Note 13 of the Notes to Consolidated Financial Statements.

Book Value Per Common Share

Sempra’s book value per common share on the last day of each of the last three fiscal years was as follows:

• $44.00 in 2023
• $41.72 in 2022
• $39.59 in 2021

The increase in 2023 was primarily due to comprehensive income exceeding dividends. In 2022, the increase was primarily due to comprehensive income exceeding dividends and a fair value that was higher than carrying value related to the change in ownership, which did not result in a change of control, from the sale of NCI in SI Partners to ADIA.

Capitalization

Our debt-to-capitalization ratio, which is calculated as total debt as a percentage of total debt and equity, was as follows:

(Dollars in millions)

2023 Form 10-K | 94

Significant changes in 2023 that affected capitalization included the following:

• Sempra: increase in long-term debt, offset by a decrease in short-term debt; and increase in equity primarily from comprehensive income exceeding dividends, sales of and contributions from NCI, offset by distributions to NCI.
• SDG&E: increase in long-term debt, offset by a decrease in short-term debt and increase in equity from comprehensive income exceeding dividends.
• SoCalGas: increase in debt and an increase in equity from comprehensive income exceeding dividends.

CRITICAL ACCOUNTING ESTIMATES

Management views certain accounting estimates as critical because their application is the most relevant, judgmental and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss critical accounting estimates that are material to our financial statements with the Audit Committee of Sempra’s board of directors.

CONTINGENCIES

Sempra, SDG&E, SoCalGas

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and if:

• information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events
• the amount of the loss or a range of possible losses can be reasonably estimated

We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.

Actual amounts realized upon settlement of contingencies may be different than amounts recorded and disclosed and may affect our results of operations, financial condition and cash flows. Details of our issues in this area are discussed in Note 16 of the Notes to Consolidated Financial Statements.

REGULATORY ACCOUNTING

Sempra, SDG&E, SoCalGas

As regulated entities, SDG&E’s and SoCalGas’ customer rates, as set and monitored by regulators, are designed to recover the cost of providing service and to provide the opportunity to realize their authorized rates of return on their investments. SDG&E and SoCalGas assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as:

• changes in the regulatory and political environment or the utility’s competitive position
• issuance of a regulatory commission order
• passage of new legislation

To the extent that circumstances associated with regulatory balances change, the regulatory balances are evaluated and adjusted if appropriate.

Significant management judgment is required to evaluate the anticipated recovery of regulatory assets and plant investments, the recognition of incentives and revenues subject to refund, as well as the existence and amount of regulatory liabilities. Adverse regulatory or legislative actions could materially impact the amounts of our regulatory assets and liabilities and could materially adversely impact our results of operations and financial condition. Specifically, if future recovery of costs ceases to be probable, all or part of the associated regulatory assets and/or plant investments would need to be written off against current period earnings, or adverse regulatory or legislative actions could give rise to material new or higher regulatory liabilities. We discuss details of SDG&E’s and SoCalGas’ regulatory assets and liabilities and additional factors that management considers when assessing probabilities associated with regulatory balances in Notes 1, 4, 15 and 16 of the Notes to Consolidated Financial Statements.

INCOME TAXES

Sempra, SDG&E, SoCalGas

Our income tax expense and related balance sheet amounts involve significant management judgments and estimates. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. When we evaluate the anticipated resolution of income tax issues, we consider:

• past resolutions of the same issue or similar issues
• the status of any income tax examination in progress
• positions taken by taxing authorities with other taxpayers with similar issues

The likelihood of deferred income tax recovery is based on analyses of the deferred income tax assets and our expectation of future taxable income, based on our strategic planning. Should a change in facts or circumstances lead to a change in judgment about the ultimate realizability of a deferred tax asset, we would record or adjust the related valuation allowance in the period that the change in facts and circumstances occurs, along with a corresponding increase or decrease in the provision for income taxes.

Actual income taxes could vary from estimated amounts because of:

• future impacts of various items, including changes in tax laws, regulations, interpretations and rulings
• our financial condition in future periods
• the resolution of various income tax issues between us and taxing and regulatory authorities

Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our results of operations, financial condition and cash flows.

We discuss these matters and additional information related to accounting for income taxes, including uncertainty in income taxes, in Note 8 of the Notes to Consolidated Financial Statements.

DERIVATIVES AND HEDGE ACCOUNTING

Sempra

We use interest rate swaps, designated as cash flow hedges, in part, to hedge interest payments related to our forecasted refinancing of the existing PA LNG Phase 1 project construction term loan facility with fixed-rate debt. The future fixed-rate debt issuances underlying these cash flow hedge relationships are largely dependent on the market demand and liquidity in the debt market. At December 31, 2023, we believe the forecasted issuances of fixed-rate debt in the related cash flow hedge relationships are probable. However, unexpected changes in market conditions in future periods could impact our ability to issue such fixed-rate debt, or the timing of such an issuance. If our assumptions regarding the nature and timing of forecasted fixed-rate debt issuances were to be inaccurate, we could be required to cease the application of hedge accounting to the related interest rate swaps, which could materially impact our results of operations. We provide details of our derivative instruments in Note 11 of the Notes to Consolidated Financial Statements.

PENSION AND PBOP PLANS

Sempra, SDG&E, SoCalGas

To measure our pension and PBOP obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We review these assumptions annually and update when appropriate.

The critical assumptions used to develop the required estimates include the following key factors:

• discount rates
• expected return on plan assets
• health care cost trend rates
• interest crediting rate on cash balance accounts
• mortality rate
• rate of compensation increases
• termination and retirement rates
• utilization of postretirement welfare benefits
• payout elections (lump sum or annuity)
• lump sum interest rates

The actuarial assumptions we use may differ materially from actual results due to:

• return on plan assets
• changing market and economic conditions
• higher or lower withdrawal rates
• longer or shorter participant life spans
• more or fewer lump sum versus annuity payout elections made by plan participants
• higher or lower retirement rates

Changes in the estimated costs or timing of pension and PBOP, or the assumptions and judgments used by management underlying these estimates (primarily the discount rate and assumed rate of return on plan assets), as well as changes in the circumstances associated with rate recovery, could have a material effect on the recorded expenses and liabilities. The following tables summarize the impact to our projected benefit obligation for pension and accumulated benefit obligation for PBOP at December 31, 2023, and 2023 net periodic benefit costs, in each case if the discount rate or assumed rate of return on plan assets were changed by 100 bps.

IMPACT DUE TO INCREASE/DECREASE IN DISCOUNT RATE

(Dollars in millions)

IMPACT DUE TO INCREASE/DECREASE IN RETURN ON PLAN ASSETS

(Dollars in millions)

For SDG&E and SoCalGas plans, the effects of the assumptions on earnings are expected to be recovered in rates and therefore are offset in regulatory accounts. We provide details of our pension and PBOP plans in Note 9 of the Notes to Consolidated Financial Statements.

SONGS ASSET RETIREMENT OBLIGATIONS

Sempra, SDG&E

SDG&E’s legal AROs related to the decommissioning of SONGS are estimated based on a site-specific study performed no less than every three years. The estimate of the obligations includes:

• estimated decommissioning costs, including labor, equipment, material and other disposal costs
• inflation adjustment applied to estimated cash flows
• discount rate based on a credit-adjusted risk-free rate
• actual decommissioning costs, progress to date and expected duration of decommissioning activities

SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s NDT.

SDG&E’s ARO related to the decommissioning of SONGS was $504 million as of December 31, 2023, based on the decommissioning cost study prepared in 2020. Changes in the estimated costs, execution strategy or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission this facility, which could have a material effect on the recorded liability.

The following table illustrates the increase to SDG&E’s and Sempra’s ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:

(Dollars in millions)

The increase in the ARO liability driven by an increase in the cost escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities. We provide additional detail in Note 15 of the Notes to Consolidated Financial Statements.

IMPAIRMENT TESTING OF LONG-LIVED ASSETS

Sempra

Whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the asset. If so, we estimate the fair value of the asset to determine the extent to which carrying value exceeds fair value. For such an estimate, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful life of a long-lived asset and to determine our intent to use the asset. Our intent to use or dispose of a long-lived asset is subject to re-evaluation and can change over time. If such an impairment test is required, the fair value of a long-lived asset can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. Critical assumptions that affect our estimates of fair value may include:

• consideration of market transactions
• future cash flows
• the appropriate risk-adjusted discount rate, including the impacts of country risk and entity risk

We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements.

IMPAIRMENT TESTING OF GOODWILL

Sempra

When determining if goodwill is impaired, the fair value of the reporting unit can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a goodwill impairment may or may not be required. When we perform a quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and compare that to its carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as a discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include:

• consideration of market transactions
• future cash flows
• projected revenue and expense growth rates
• the appropriate risk-adjusted discount rate, including the impacts of country risk and entity risk

In 2022, we performed a quantitative goodwill impairment test and determined that the estimated fair values of our reporting units in Mexico to which goodwill was allocated were substantially above their respective carrying values as of October 1, our goodwill impairment testing date. Upon performing a qualitative analysis as of October 1, 2023, we determined that it was not more likely than not that the fair value of such reporting units was less than their respective carrying values. Our goodwill impairment test is determined based on assumptions existing as of that point in time. Changes in the business (such as loss of future cash flows from customer disputes, renegotiation of customer contracts or the macroeconomic environment, including rising interest rates) may result in us having to perform an interim goodwill impairment test, which could result in an impairment of our goodwill.

NEW ACCOUNTING STANDARDS

We discuss the recent accounting pronouncements that have had or may have a significant effect on our financial statements and/or disclosures in Note 2 of the Notes to Consolidated Financial Statements.

Market risk is the risk of erosion of our cash flows, earnings, asset values or equity due to adverse changes in commodity market prices, interest rates and foreign currency and inflation rates.

MARKET RISK POLICIES

Sempra has policies governing its market risk management and trading activities. Sempra, SDG&E, SoCalGas and Sempra Infrastructure maintain separate risk management committees, organizations and processes to provide oversight of these activities for their respective businesses. The committees consist of senior officers who establish policy, oversee energy risk management activities, and monitor the results of trading and other activities to help ensure compliance with our stated energy risk management and trading policies. These activities include, but are not limited to, monitoring of market positions that create credit, liquidity and market risk. The respective oversight organizations and committees are independent from energy procurement departments.

Along with other tools, we use VaR and liquidity metrics to measure our exposure to market risk associated with commodity portfolios. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. We use a variance-covariance VaR model at a 95% confidence level. A liquidity metric is intended to monitor the amount of financial resources needed for meeting potential margin calls as forward market prices move. VaR and liquidity risk metrics are independently verified by the respective risk management oversight organizations.

SDG&E and SoCalGas use natural gas derivatives and SDG&E uses electricity derivatives to manage natural gas and electric price risk associated with servicing load requirements. The use of natural gas and electricity derivatives is subject to certain limitations imposed by company policy and regulatory requirements. SDG&E’s risk management and transacting activity plans for electricity derivatives are also required to be filed with, and have been approved by, the CPUC. SoCalGas is also subject to certain regulatory requirements and thresholds related to natural gas procurement under the GCIM. We discuss revenue recognition in Note 3 and additional market-risk information regarding derivative instruments in Note 11 of the Notes to Consolidated Financial Statements.

We have exposure to changes in commodity prices, interest rates and foreign currency and inflation rates. The following discussion of these primary market-risk exposures as of December 31, 2023 includes a discussion of how these exposures are managed.

COMMODITY PRICE RISK

Market risk related to physical commodities is created by volatility in the prices and basis of certain commodities. Our various subsidiaries are exposed, in varying degrees, to commodity price risk, primarily to prices in the natural gas and electricity markets. Our policy is to manage this risk within a framework that considers the specific markets and operating and regulatory environments of each subsidiary.

Sempra Infrastructure is exposed to commodity price risk indirectly through its LNG, natural gas pipelines and storage, and power-generating assets. Sempra Infrastructure has utilized and may continue to utilize commodity contracts, including physical and financial derivatives, in an effort to mitigate these risks and optimize the value of these assets. These transactions are typically priced based on market indices, but may also include fixed price purchases and sales of commodities. Any residual exposure is monitored as described above. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes in commodity prices have in the past and could in the future result in earnings volatility as the economic offset of these derivatives may not be recorded at fair value. A significant decrease in the fair value of these economic hedges could also result in higher collateral requirements, which could negatively impact our liquidity and our ability to continue to mitigate our commodity risk exposure. We try to structure our hedging transactions with the objective that over time (i) realized gains and losses on our economic hedges would be largely offset by gains and losses related to our purchases or sales of natural gas and (ii) we would realize the economic benefit we anticipated at the time we structured the original transaction.

A hypothetical 10% change in commodity prices would have resulted in a change in the fair value of our commodity-based natural gas and electricity derivatives of $14 million and $24 million at December 31, 2023 and 2022, respectively. The impact of a change in energy commodity prices on our commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled and does not typically include the generally offsetting impact of our underlying asset positions.

SDG&E and SoCalGas separately manage risk within the parameters of their market risk management frameworks. In addition, their market-risk exposure is limited due to CPUC-authorized rate recovery of the costs of commodity purchases, interstate and intrastate transportation, and storage activity. However, SoCalGas may, at times, be exposed to market risk as a result of the GCIM, which rewards or penalizes the utility for commodity costs below or above certain benchmarks. The one-day VaR for SDG&E’s and SoCalGas’ commodity positions were $2 million and $4 million, respectively, at December 31, 2023 and $25 million and $2 million, respectively, at December 31, 2022.

INTEREST RATE RISK

We are exposed to fluctuations in interest rates primarily from our short- and long-term debt. Subject to regulatory constraints, we periodically enter into interest rate swap agreements to moderate our exposure to interest rate changes and to lower our overall cost of borrowing.

The table below shows the nominal amount of our debt:

NOMINAL AMOUNT OF DEBT(1)

(Dollars in millions)

(1) After the effects of interest rate swaps. Before reductions for unamortized discount and debt issuance costs and excluding finance lease obligations.

An interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings attributable to common shares (but disregarding capitalized interest and impacts on equity earnings from debt at our equity method investees) that would result from a hypothetical change in market interest rates. Earnings attributable to common shares are affected by changes in interest rates on short-term debt and variable-rate long-term debt. If weighted-average interest rates on short-term debt outstanding at December 31, 2023 increased or decreased by 10%, the change in earnings attributable to common shares over the 12-month period ending December 31, 2024 would be approximately $9 million. If interest rates increased or decreased by 10% on all variable-rate long-term debt at December 31, 2023, after considering the effects of interest rate swaps, the change in earnings attributable to common shares over the 12-month period ending December 31, 2024 would be approximately $5 million.

We provide further information about debt and interest rate swap transactions in Notes 7 and 11, respectively, of the Notes to Consolidated Financial Statements.

We also are subject to the effect of interest rate fluctuations on the assets of our pension plans, PBOP plans, and SDG&E’s NDT. However, we expect the effects of these fluctuations, as they relate to Sempra California, to be reflected in future rates.

FOREIGN CURRENCY EXCHANGE RATE RISK AND INFLATION EXPOSURE

We discuss our foreign currency exchange rate risk and inflation exposure in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations.”

The hypothetical effect for every 10% appreciation in the U.S. dollar against the Mexican peso, in which we have operations and investments, are as follows:

(Dollars in millions)

(1) After the effects of foreign currency derivatives.

(2) Amount represents the impact to earnings for a change in the average exchange rate throughout the reporting period.

(3) Amount primarily represents the effects of currency exchange rate movement from December 31, 2023 on monetary assets and liabilities and remeasurement of non-U.S. deferred income tax balances at our Mexican subsidiaries.

(4) Amount represents the effects of currency exchange rate movement from December 31, 2023 that would be recorded to OCI at the end of the reporting period.

Monetary assets and liabilities at our Mexican subsidiaries and JVs that are denominated in U.S. dollars may fluctuate significantly throughout the year. These monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. Based on a net monetary liability position of $4.5 billion, including those related to our investments in JVs, at December 31, 2023, the hypothetical effect of a 10% increase in the Mexican inflation rate is approximately $91 million lower earnings attributable to common shares as a result of higher income tax expense for our consolidated entities, as well as lower equity earnings for our JVs.

In 2023 and 2022, SDG&E and SoCalGas experienced inflationary pressures from increases in various costs, including the cost of natural gas, electric fuel and purchased power, labor, materials and supplies, as well as availability of labor and materials. During this period, Sempra Texas Utilities experienced increased costs of labor and materials and does not have specific regulatory mechanisms that allow for recovery of higher costs due to inflation; rather, recovery is limited to rate updates through capital trackers and base rate reviews, which may result in partial non-recovery due to the regulatory lag. If such costs were to continue to be subject to significant inflationary pressures and we are not able to fully recover such higher costs in rates or there is a delay in recovery, these increased costs may have a significant effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.

In 2023 and 2022, Sempra Infrastructure experienced inflationary pressures from increases in various costs, including the cost of labor, materials and supplies. Sempra Infrastructure generally secures long-term contracts that are U.S. dollar-denominated or referenced and are periodically adjusted for market factors, including inflation, and Sempra Infrastructure generally enters into lump-sum contracts for its large construction projects in which much of the risk during construction is absorbed or hedged by the EPC contractor. If additional costs were to become subject to significant inflationary pressures, we may not be able to fully recover such higher costs through contractual adjustments for inflation, which may have a significant effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra, SDG&E, SoCalGas

Sempra, SDG&E and SoCalGas maintain disclosure controls and procedures designed to ensure that information required to be disclosed in their respective reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to the management of each company, including each respective principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2023, the end of the period covered by this report. Based on these evaluations, the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level as of such date.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Sempra, SDG&E, SoCalGas

The respective management of Sempra, SDG&E and SoCalGas is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f).

Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on these evaluations, each company’s management concluded that its internal control over financial reporting was effective as of December 31, 2023. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2023, as stated in their reports, which are included in this annual report on Form 10-K.

There have been no changes in Sempra’s, SDG&E’s or SoCalGas’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, any such company’s internal control over financial reporting.

To the Shareholders and Board of Directors of Sempra:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Sempra and subsidiaries (“Sempra”) as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, Sempra maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements as of and for the year ended December 31, 2023, of Sempra and our report dated February 27, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

Sempra’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Sempra’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sempra in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

To the Shareholder and Board of Directors of San Diego Gas & Electric Company:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of San Diego Gas & Electric Company (“SDG&E”) as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, SDG&E maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements as of and for the year ended December 31, 2023, of SDG&E and our report dated February 27, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

SDG&E’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on SDG&E’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SDG&E in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP

To the Shareholders and Board of Directors of Southern California Gas Company:

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Southern California Gas Company (“SoCalGas”) as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, SoCalGas maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the financial statements as of and for the year ended December 31, 2023, of SoCalGas and our report dated February 27, 2024, expressed an unqualified opinion on those financial statements.

Basis for Opinion

SoCalGas’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on SoCalGas’ internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SoCalGas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ DELOITTE & TOUCHE LLP