EDGAR 10-K Filing

Company CIK: 1032208
Filing Year: 2022
Filename: 1032208_10-K_2022_0001032208-22-000007.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS
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 through regulated public utilities.
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.
We have a strong and growing presence in Mexico through a diverse portfolio of energy infrastructure projects and assets serving Mexico’s growing energy needs. Our energy infrastructure footprint also includes our 50.2% interest in Cameron LNG JV, which is a natural gas liquefaction export facility operating in Louisiana, and construction and development of LNG projects and assets on the Gulf Coast and Pacific Coast of North America.
In the fourth quarter of 2021, we formed Sempra Infrastructure, a new segment that includes the operating companies of our subsidiary, SI Partners, as well as a holding company and certain services companies. Through an internal reorganization, we consolidated the assets of our LNG business (previously included in our Sempra LNG segment) and our ownership of IEnova (previously included in our Sempra Mexico segment) under Sempra Global (previously included in Parent and other), which was renamed SI Partners. This reorganization simplifies Sempra’s ownership and management of its non-utility, energy infrastructure assets in North America by consolidating them under a single platform. As a result, the Sempra LNG and Sempra Mexico segments no longer exist. Our historical segment disclosures have been restated to conform with the current presentation, so that all segment discussions reflect the revised segment information of our four separate reportable segments.
In 2018, we announced a multi-phase portfolio optimization initiative designed to sharpen our strategic focus on North America. We have since executed on that initiative by completing the sales of our renewables businesses and our non-utility natural gas storage assets in the U.S., and by completing the sales of our businesses in South America. We present the South American businesses as discontinued operations throughout this report.
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 goal of delivering safe and reliable energy to our customers and increasing shareholder value.
DESCRIPTION OF BUSINESS BY SEGMENT
Our business activities are organized under the following reportable segments:
▪SDG&E
▪SoCalGas
▪Sempra Texas Utilities
▪Sempra Infrastructure
SDG&E
SDG&E is a regulated public utility that provides electric services to a population of, at December 31, 2021, approximately 3.6 million and natural gas services to approximately 3.3 million of that population, covering a 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, 2021 covered the following territory:
Electric 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 2,148 miles of transmission lines, 23,829 miles of distribution lines and 160 substations at December 31, 2021. 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 1,162 MW, although it can be less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed and operated by SDG&E with import capability of 1,000 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, although 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. To meet customer demand, 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 purchased-power contracts or through purchases on the spot market. SDG&E does not earn any return on commodity sales volumes. SDG&E’s supply at December 31, 2021 was as follows:
SDG&E - ELECTRIC RESOURCES(1)
Contract Net operating
expiration date capacity (MW) % of total
Owned generation facilities, natural gas(2)
1,204 24 %
Purchased-power contracts:
Renewables:
Wind 2023 to 2035 1,131 22
Solar 2030 to 2042 1,350 26
Other 2022 and thereafter 168 3
Tolling and other 2022 to 2042 1,292 25
Total 5,145 100 %
(1) Excludes approximately 128 MW of energy storage owned and approximately 164 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 of which 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 purchased-power contracts under which SDG&E provides natural gas for generation 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 purchased-power arrangements. Purchases are from various southwestern U.S. suppliers and are primarily priced based on published monthly bid-week indices.
SDG&E is a participant 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 located 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:
SDG&E - ELECTRIC CUSTOMER METERS AND VOLUMES
Customer meter count Volumes(1)
(millions of kWh)
December 31, Years ended December 31,
2021 2021 2020 2019
Residential 1,282,331 5,657 6,606 5,982
Commercial 72,216 4,128 5,873 6,295
Industrial 683 1,398 1,842 2,044
Street and highway lighting 3,487 115 77 76
1,358,717 11,298 14,398 14,397
CCA and DA 137,098 5,916 3,482 3,549
Total 1,495,815 17,214 17,880 17,946
(1) Includes intercompany sales.
SDG&E currently provides procurement service for most of its customer load. However, some customers can 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) offers such a program and DA is currently limited by a cap based on gigawatt hours. A number of jurisdictions in SDG&E’s territory, including the City and County of San Diego and 14 other
municipalities, have implemented, are implementing or are considering implementing CCA. Based on our current expectations, SDG&E could procure energy for less than half of its current customer load by December 31, 2022.
SDG&E’s historical energy procurement may exceed the needs of its bundled customers as customers elect CCA and DA service. Accordingly, the associated costs of the utility’s procured resources could then be borne by SDG&E’s remaining bundled procurement customers. To help achieve the goal of ratepayer indifference (whether or not customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. SDG&E implemented the framework on January 1, 2019, by adopting several refinements designed to more equitably share energy procurement costs among customers served by SDG&E and customers 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, 2021, 2020 and 2019, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 1,620 MW, 1,423 MW and 1,233 MW, respectively.
Demand for electricity 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 result in significant increases in 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, development of new natural gas supply sources, demand for natural gas and general economic conditions, can also result in significant shifts in the market price of electricity, which may in turn impact demand. Demand for electricity is also impacted by seasonal weather patterns (or “seasonality”), tending to increase in the summer months to meet cooling load and in the winter months to meet heating load.
Competition. SDG&E faces competition to serve its customer load from the growth in distributed and local power generation, 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. However, SDG&E does not earn any return on commodity sales.
Natural Gas Utility Operations
We describe SDG&E’s natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.”
SoCalGas
SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission and storage system that supplies natural gas to a population of, at December 31, 2021, approximately 22 million, covering a 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, 2021 covered the following territory:
Natural Gas Utility Operations
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, 2021, SoCalGas’ natural gas facilities included 3,047 miles of transmission and storage pipelines, 51,724 miles of distribution pipelines, 48,549 miles of service pipelines and nine transmission compressor stations, and SDG&E’s natural gas facilities consisted of 176 miles of transmission pipelines, 9,058 miles of distribution pipelines, 6,686 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 LNG-sourced 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 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.
To support the delivery of natural gas supplies to its distribution system and to meet the needs of customers, SoCalGas has firm interstate pipeline capacity contracts that require the payment of fixed reservation charges to reserve firm 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 135 injection, withdrawal and observation wells that provide natural gas storage services for core, noncore and non-end-use customers. SoCalGas’ and SDG&E’s core customers are allocated a portion of SoCalGas’ storage capacity. SoCalGas uses the remaining storage capacity for load balancing services for all customers and, if available, to others, including SDG&E for its non-core customer requirements. 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 the CPUC limitations described below, represents 63% of SoCalGas’ natural gas storage capacity. SoCalGas discovered a natural gas leak at one of its wells at the Aliso Canyon natural gas storage facility in October 2015 and permanently sealed the well in February 2016. SoCalGas was subsequently authorized to make limited withdrawals and injections of natural gas at the Aliso Canyon natural gas storage facility and, on an interim basis, has been directed by the CPUC to maintain up to 41.16 Bcf of working gas at the facility to help achieve reliability for the region at reasonable rates as determined by the CPUC. To help maintain system reliability, the CPUC issued a protocol authorizing withdrawals of natural gas from the facility if available gas supply and gas prices reach defined thresholds for SoCalGas’ system, as determined by the protocol. We discuss the Leak 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.
SEMPRA CALIFORNIA - NATURAL GAS CUSTOMER METERS AND VOLUMES
Customer meter count Volumes (Bcf)(1)
December 31, Years ended December 31,
2021 2021 2020 2019
SDG&E:
Residential
874,460
Commercial
29,060
Electric generation and transportation
2,630
Natural gas sales
46 43 45
Transportation
38 40 26
Total
906,150 84 83 71
SoCalGas:
Residential
5,823,610
Commercial
248,560
Industrial
24,660
Electric generation and wholesale
Natural gas sales
314 312 329
Transportation
568 572 547
Total
6,096,870 882 884 876
(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.
Demand for natural gas 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 new natural gas supply sources, demand for natural gas outside California, and general economic conditions can also result in significant shifts in market price, 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 help provide electric reliability in our California service territories.
The natural gas distribution business is subject to seasonality, and cash provided by operating activities generally is greater during and immediately following the winter heating months. As is prevalent in the industry, but subject to current 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, 2021 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 as permitted by law.
At December 31, 2021, Oncor had 4,537 employees, including 772 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, 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 and maintenance 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, 2021, Oncor’s transmission system included approximately 18,249 circuit miles of transmission lines, a total of 1,174 transmission and distribution substations, and interconnection to 130 third-party generation facilities totaling 45,403 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 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 3,679 distribution feeders.
Oncor’s distribution system included more than 3.8 million points of delivery at December 31, 2021 and consisted of 122,441 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, delivering electricity to more than 3.8 million homes and businesses, operating more than 140,000 miles of transmission and distribution lines as of December 31, 2021 in a territory with an estimated population of approximately 13 million. The consumers of the electricity Oncor delivers are free to choose their electricity supplier from retail electric providers who compete for their business. Accordingly, Oncor is not a seller of electricity, nor does it purchase electricity for resale. Rather, Oncor provides transmission services to its electricity distribution business as well as non-affiliated electricity distribution companies, cooperatives and municipalities and distribution services to retail electric providers that sell electricity to retail customers. At December 31, 2021, Oncor’s distribution customers consisted of approximately 95 retail electric providers and certain electric cooperatives in its certificated service area.
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 distributed energy resources 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, 2021, approximately 63 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.
Sempra Infrastructure owned an 80% interest in SI Partners at December 31, 2021, with the remaining 20% interest owned by KKR upon completion of its purchase of a NCI in SI Partners on October 1, 2021. On December 21, 2021, Sempra entered into a purchase and sale agreement with ADIA, pursuant to which ADIA agreed to acquire a 10% NCI in SI Partners. The consummation of the ADIA transaction is subject to the receipt of certain regulatory and third-party approvals, and other customary closing conditions. Following the closing of the ADIA transaction, Sempra, KKR and ADIA would directly or
indirectly own 70%, 20%, and 10%, respectively, of the outstanding Class A Units of SI Partners. SI Partners has two authorized classes of limited partnership interests designated as “Class A Units” (which are common voting units) and “Sole Risk Interests” (which are only owned by Sempra, are non-voting and are not considered in the calculation of each limited partner’s respective ownership interests, subject to certain restrictions). We discuss KKR’s purchase and ADIA’s pending purchase of NCI in SI Partners, as well as SI Partners’ limited partnership agreement that governs the partners’ respective rights and obligations in respect of their ownership interests in SI Partners in Note 1 of the Notes to Consolidated Financial Statements.
SI Partners held a 100% ownership interest in Sempra LNG Holding, LP and a 99.9% ownership interest in IEnova at December 31, 2021, following completion of the exchange offer and cash tender offer to acquire the publicly owned shares of IEnova, which we discuss in Note 1 of the Notes to Consolidated Financial Statements. SI Partners simplifies Sempra’s ownership and management of its non-utility, energy infrastructure assets in North America by consolidating them 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.
At December 31, 2021, Sempra Infrastructure owned or held interests in the following assets:
LNG and Net-Zero Solutions
Sempra Infrastructure’s LNG and Net-Zero Solutions business line is comprised of a natural gas liquefaction portfolio in operation, construction or development, and is focused on energy diversification and the clean energy transition in markets that our customers serve.
Cameron LNG JV. Sempra Infrastructure 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 Cameron LNG JV Phase 1, a natural gas liquefaction, export, regasification and import facility with three natural gas pre-treatment, processing and liquefaction trains. Cameron LNG JV Phase 1 is located in Hackberry, Louisiana, along the Calcasieu Ship Channel, which handles significant industrial shipping, including large oil and LNG tankers, and is well
positioned to supply the Atlantic and Pacific markets. Cameron LNG JV Phase 1 achieved commercial operations of Train 1, Train 2 and Train 3 in August 2019, February 2020 and August 2020, respectively. 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. Cameron LNG JV 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 Mexico and Gazprom 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. Shell Mexico and Gazprom have commenced binding arbitration to terminate these agreements and seek other relief. The land on which the ECA Regas Facility and the proposed ECA LNG liquefaction projects is situated as well as land adjacent to those properties are the subject of litigation. We discuss the ECA Regas Facility arbitration and land litigation 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 sale and purchase agreement with Tangguh PSC through 2029, which we discuss below, and ECA LNG Phase 1 will be the sole user of this capacity thereafter.
Asset and Supply Optimization. Sempra Infrastructure has an LNG sale and purchase agreement 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 sale and purchase agreement 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.
ECA LNG Phase 1. Sempra Infrastructure 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 ECA LNG Phase 1 to begin producing LNG by the end of 2024.
ECA LNG Phase 1 has definitive 20-year LNG sale and purchase agreements 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.”
Additional Potential LNG and Net-Zero Solutions’ Projects. Sempra Infrastructure is evaluating the following development opportunities:
▪Cameron LNG JV Phase 2 project, an expansion of Cameron LNG JV’s liquefaction export facility
▪ECA LNG Phase 2 project, a large-scale natural gas liquefaction export project to be located at the site of Sempra Infrastructure’s existing ECA Regas Facility in Baja California, Mexico
▪Port Arthur LNG, a large-scale natural gas liquefaction export project and associated infrastructure on a greenfield site in the vicinity of Port Arthur, Texas located along the Sabine-Neches waterway
▪Vista Pacifico LNG, a mid-scale natural gas liquefaction export project and associated infrastructure in the vicinity of Topolobampo in Sinaloa, Mexico
▪Baja Sur LNG, an early-stage regasification facility in La Paz, Baja California Sur, Mexico
▪Hackberry Carbon Storage, a carbon capture and sequestration project that is intended to reduce emissions at Cameron LNG JV
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 (but not limited to) 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 elastic markets in gas and oil drilling and production resulting in efficient unit costs of gas production
▪availability of extensive pre-existing 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. It is expected that North American LNG exports will increase competition for current and future global natural gas demand, and thereby facilitate additional growth of a global commodity market for natural gas and LNG.
Additionally, our Cameron LNG JV co-owners and customers compete globally to market and sell LNG to end users, including gas and electric utilities located in LNG-importing countries around the world. By providing liquefaction services, Cameron LNG JV and future LNG export development projects compete indirectly 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.
The LNG regasification business is impacted by worldwide LNG market prices. High LNG prices in markets outside the market in which Sempra Infrastructure’s ECA Regas Facility operates have resulted and could continue to result in lower-than-expected deliveries of LNG cargoes to the ECA Regas Facility, which could increase costs if Sempra Infrastructure is instead required to obtain LNG in the open market at prevailing prices. Any inability to obtain expected LNG cargoes could also impact Sempra Infrastructure’s ability to maintain the minimum level of LNG required to keep the ECA Regas Facility in operation at the proper temperature. Prices in international LNG markets through which Sempra Infrastructure must purchase natural gas to meet its contractual obligations to deliver natural gas to customers may also affect how Sempra Infrastructure optimizes its assets and supply, which could have an adverse impact on its earnings.
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, 2021, these systems consisted of 1,850 miles of natural gas transmission pipelines plus 124 miles in development, 16 natural gas compression stations plus one in development, 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, CENAGAS, PEMEX, Shell Mexico, Gazprom and other similar counterparties. Some of these pipeline assets are affected by disputes related to the property on which the pipelines are located, which we discuss in Note 16 of the Notes to Consolidated Financial Statements and “Part I - Item 1A. Risk Factors.”
Sempra Infrastructure owns a 40-mile natural gas pipeline in south Louisiana, the Cameron Interstate Pipeline, which links the Cameron LNG JV Phase 1 facility in Cameron Parish in Louisiana, to five interstate 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 Cameron LNG JV Phase 1.
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, 2021, Ecogas had approximately 2,842 miles of distribution pipeline, and approximately 143,000 customer meters serving more than 489,000 residential, commercial and industrial consumers with sales volume of approximately 10 MMcf per day in 2021. 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, 2021, 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 state of Tamaulipas, Mexico to Sempra Infrastructure’s delivery 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 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 Mexico states of Baja California, Colima, Puebla, Sinaloa, Veracruz and Valle de México for private companies. The Veracruz marine terminal reached commercial operations in March 2021 and the inland terminal in the vicinity of Mexico City reached commercial operations in July 2021. The two terminals have a combined storage capacity of more than 2.7 million barrels. 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 Chevron Corporation, 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.
At December 31, 2021, Sempra Infrastructure had marine and inland terminals under development and construction, with a projected storage capacity of approximately 5 million barrels. We expect the Topolobampo marine terminal to reach commercial operations in the first half of 2022. The inland terminal in the vicinity of Puebla has been temporarily shut down during the pendency of an industrywide investigation initiated by the CRE to enforce Mexico’s fuel procurement laws and its storage permit may be at risk due to a separate CRE administrative proceeding. We discuss this investigation and other risks and uncertainties related to the construction of these projects in “Part I - Item 1A. Risk Factors” and “Part II - Item 7. MD&A - Capital Resources and Liquidity - Sempra Infrastructure.”
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.
Clean Power
Sempra Infrastructure’s Clean Power business line consists of a renewable energy infrastructure portfolio and a natural gas-fired power plant in Mexico.
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, 2021, Sempra Infrastructure had a fully contracted, total nameplate capacity of 1,044 MW related to its wind and solar power generation facilities that were either fully operating or under construction. 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.”
SEMPRA INFRASTRUCTURE - RENEWABLE POWER GENERATION
Location Contract expiration date Nameplate capacity (MW)
Wind power generation facilities:
ESJ - first phase
Tecate, Baja California 2035 155
ESJ - second phase(1)
Tecate, Baja California 2042 108
Ventika Nuevo León, Mexico
2036 252
Solar power generation facilities:
Border Solar Ciudad Juarez, Chihuahua 2032 and 2037 150
Don Diego Solar Benjamin Hill, Sonora 2034 and 2037 125
Pima Solar Caborca, Sonora 2038 110
Rumorosa Solar Tecate, Baja California 2034 44
Tepezalá Solar Aguascalientes 2034 100
Total 1,044
(1) Commenced commercial operations in January 2022.
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 commenced commercial operations in June 2003. The power plant 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.
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 ERR 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 phase of ESJ, a wind power generation facility that delivers energy into California, has been certified by the CEC and is in compliance with the RPS Program as of December 31, 2021. Sempra Infrastructure is pursuing ERR certification for the second phase of ESJ.
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.
Discontinued Operations
We completed the sales of our equity interests in our Peruvian businesses in April 2020 and our Chilean businesses in June 2020. These South American businesses included our former 100% interest in Chilquinta Energía (an electric distribution utility in Chile), our former 83.6% interest in Luz del Sur (an electric distribution utility in Peru) and our former interests in two energy-services companies, Tecnored and Tecsur, which provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, respectively, as well as third parties. These businesses and certain activities associated with these businesses are presented as discontinued operations in this report. We provide further information about discontinued operations in Note 5 of the Notes to Consolidated Financial Statements.
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 for 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 costs of transportation and distribution. This analysis is one of many resource materials used to support SDG&E’s and SoCalGas’ long-term investment decisions.
California requires certain of its 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 both the CPUC and the CEC, are generally known as the RPS Program.
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 operation and maintenance of SoCalGas’ natural gas storage facilities are regulated by CalGEM and the CPUC, as well as various other state and local agencies.
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 rate and service orders 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 the safety, radiological and environmental aspects of these facilities. 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 own regulations. SDG&E, SoCalGas, Oncor and Sharyland Utilities are therefore 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 services 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, participate with the ERCOT ISO and other member utilities in its operations. Each of these Texas utilities has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for 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 franchises with the two counties and the 27 cities in or adjoining its electric service territory, and natural gas franchises with the one county and the 18 cities in its natural gas service territory. These franchises allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of natural gas and/or electricity. Most of the franchises have indefinite lives with no expiration dates. Some of SDG&E’s natural gas and electric franchises have fixed expiration dates that range from 2028 to 2035. In June 2021, the City of San Diego approved ordinances granting to SDG&E the natural gas and electric franchises for the city. These franchise agreements 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 with a supermajority vote. The agreements went into effect in July 2021.
SoCalGas has natural gas franchises with the 12 counties and the 223 cities in its service territory. These franchises allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the franchises have indefinite lives with no expiration date. Some franchises have fixed expiration dates, ranging from 2023 to 2069, including the Los Angeles County franchise, which is scheduled to expire in June 2023.
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. Sempra Infrastructure’s other potential natural gas liquefaction export projects would, if completed, be subject to similar regulation.
SDG&E and SoCalGas and businesses that Sempra Infrastructure invests in 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, the Mexican Safety, Energy and Environment Agency (Agencia de Seguridad, Energía y Ambiente), 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 Comisión Federal de Competencia Económica (Mexico’s Competition Commission) 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 liquid fuels.
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 its investment. The proceeding generally establishes the test year revenue requirements, which authorizes 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 determines a utility’s authorized capital structure and authorized 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 interim years between cost of capital proceedings and considers changes in the cost of capital based on changes in interest rates based on the applicable 12-month average Moody’s utility bond index. The index applicable to each utility is based on each utility’s credit rating. The CCM benchmark rates for SDG&E and SoCalGas are the basis of comparison to determine if future measurement periods “trigger” the CCM. The trigger occurs if the change in the applicable average Moody’s utility bond index relative to the CCM benchmark is larger than plus or minus 100 bps. 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 and the applicable 12-month average Moody’s utility bond index, unless the CPUC accepts a utility’s interim application to have its cost of capital assessed between regular cost of capital proceedings based on an extraordinary or catastrophic event that materially impacts the utility’s cost of capital and affects utilities differently than the market as a whole. SDG&E filed such an interim application in August 2021 due to the ongoing effects of the COVID-19 pandemic.
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 (1) a base period of historical costs and a forecast of capital investments, and (2) 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.
We discuss SDG&E’s TO5 filing with the FERC in Note 4 of the Notes to Consolidated Financial Statements.
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 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 costs and capital related costs (such as depreciation, taxes and return on rate base), including:
▪costs to purchase natural gas and electricity;
▪costs associated with administering public purpose, demand response, 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 within a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met at the time 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 for programs authorized, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers.
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 of recovery could be significantly less than requested levels. There can also be no assurance that the PUCT will approve other items proposed 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 return on invested capital allowed by the PUCT.
The PUCT’s substantive rules allow Texas electric utilities providing wholesale or retail distribution service to file, under certain circumstances, once per year and up to four rate adjustments between comprehensive base rate proceedings to recover distribution-related investments on an interim basis. The PUCT’s substantive rules also allow the Texas utilities to update their transmission rates periodically on an interim basis to reflect changes in invested capital. These “capital tracker” provisions are intended to encourage investment in the electric system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission and distribution investments.
Capital Structure and Return on Equity
Oncor has a PUCT-authorized ROE of 9.8% and an authorized regulatory capital structure of 57.5% debt to 42.5% equity. On May 10, 2021, Oncor filed an application with the PUCT requesting to extend its base rate review filing deadline from October 1, 2021 to June 1, 2022. On July 29, 2021, the PUCT approved an order granting the extension. As a result, Oncor’s next base rate review must be filed on or before June 1, 2022.
Sharyland Utilities’ PUCT-authorized ROE is 9.38% and its authorized regulatory capital structure is 55% debt to 45% equity. Sharyland Utilities filed its 2020 rate case with the PUCT in December 2020 and received PUCT approval on July 15, 2021.
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 the period 2021 through 2025. Ecogas expects to receive a decision in the first half of 2022. 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. This mechanism permits SDG&E and SoCalGas 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 have the opportunity to 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 in rates the costs to comply with these standards. We discuss GHG emissions standards and credits further in Note 1 of the Notes to Consolidated Financial Statements.
We discuss environmental matters concerning the Leak in Note 16 of the Notes to Consolidated Financial Statements and in “Part I - Item 1A. Risk Factors.”
OTHER MATTERS
Information About Our Executive Officers
INFORMATION ABOUT EXECUTIVE OFFICERS AT SEMPRA
Name Age(1)
Positions held over last five years Time in position
Jeffrey W. Martin 60 Chairman December 2018 to present
Chief Executive Officer May 2018 to present
President March 2020 to present
Executive Vice President and Chief Financial Officer January 2017 to May 2018
Kevin C. Sagara 60 Executive Vice President and Group President June 2020 to present
Chief Executive Officer, SDG&E September 2018 to June 2020
President, Sempra Renewables October 2013 to September 2018
Trevor I. Mihalik 55 Executive Vice President and Chief Financial Officer May 2018 to present
Senior Vice President December 2013 to April 2018
Controller and Chief Accounting Officer July 2012 to April 2018
Peter R. Wall 50 Senior Vice President April 2020 to present
Controller and Chief Accounting Officer May 2018 to present
Vice President May 2018 to April 2020
Vice President and Chief Financial Officer, Sempra Infrastructure January 2017 to April 2018
Karen L. Sedgwick 55 Chief Administrative Officer and Chief Human Resources Officer December 2021 to present
Senior Vice President and Chief Human Resources Officer September 2020 to December 2021
Chief Human Resources Officer and Chief Administrative Officer,
SDG&E
April 2019 to September 2020
Vice President and Treasurer August 2018 to April 2019
Vice President, Audit Services January 2014 to August 2018
(1) Ages are as of February 25, 2022.
INFORMATION ABOUT EXECUTIVE OFFICERS AT SDG&E
Name Age(1)
Positions held over last five years Time in position
Caroline A. Winn 58 Chief Executive Officer August 2020 to present
Chief Operating Officer January 2017 to July 2020
Bruce A. Folkmann 54 President August 2020 to present
Chief Financial Officer March 2015 to present
Senior Vice President August 2019 to July 2020
Controller, Chief Accounting Officer and Treasurer March 2015 to August 2020
Vice President March 2015 to August 2019
Vice President, Controller, Chief Financial Officer, Chief Accounting
Officer and Treasurer, SoCalGas
March 2015 to June 2019
Valerie A. Bille 43 Vice President, Controller, Chief Accounting Officer and Treasurer August 2020 to present
Assistant Controller, Sempra June 2019 to August 2020
Assistant Controller June 2018 to June 2019
Director, Utility Financial Reporting June 2017 to June 2018
Director, Financial Systems and Business Controls August 2015 to June 2017
Diana L. Day 57 Senior Vice President and General Counsel August 2020 to present
Chief Risk Officer August 2019 to present
Vice President and General Counsel January 2019 to August 2020
Acting General Counsel September 2017 to January 2019
Vice President of Enterprise Risk Management and Compliance,
SDG&E and SoCalGas
June 2014 to January 2019
(1) Ages are as of February 25, 2022.
INFORMATION ABOUT EXECUTIVE OFFICERS AT SOCALGAS
Name Age(1)
Positions held over last five years Time in position
Scott D. Drury 56 Chief Executive Officer August 2020 to present
President, SDG&E January 2017 to July 2020
Maryam S. Brown 46 President March 2019 to present
Vice President of Federal Government Affairs, Sempra September 2016 to March 2019
Jimmie I. Cho 57 Chief Operating Officer January 2019 to present
Senior Vice President of Customer Services and Gas Distribution
Operations
April 2018 to January 2019
Senior Vice President of Gas Distribution Operations, SDG&E
April 2018 to January 2019
Senior Vice President of Gas Engineering and Distribution Operations,
SoCalGas and SDG&E
October 2017 to April 2018
Senior Vice President of Gas Operations and System Integrity, SoCalGas and SDG&E
June 2014 to October 2017
Mia L. DeMontigny 49 Chief Financial Officer, Controller, Chief Accounting Officer and Treasurer June 2019 to present
Vice President June 2019 to August 2021
Assistant Controller, Sempra August 2015 to June 2019
David J. Barrett 57 Vice President and General Counsel
January 2019 to present
Associate General Counsel of Gas Infrastructure, Sempra June 2018 to January 2019
Assistant General Counsel of Gas Infrastructure, Sempra February 2017 to June 2018
Jeffery L. Walker 61 Senior Vice President, Chief Administrative and Diversity Officer November 2020 to present
Vice President, Customer Solutions March 2019 to November 2020
Director of Special Projects January 2019 to March 2019
Director, SoCalGas Advanced Meter January 2014 to January 2019
(1) Ages are as of February 25, 2022.
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 training programs, benchmarking, review and analysis of safety trends, and sharing lessons learned from safety incidents 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 Safety, Sustainability and Technology committee of the Sempra board of directors 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 can 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, workshops 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. In addition, we offer a variety of in-person and virtual 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 Conduct as well as resources such as Sempra’s ethics and compliance hotline. 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. Sempra’s board of directors is chartered with overseeing our culture.
The table below shows the number of employees for each of our registrants at December 31, 2021, as well as the percentage 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 2021 and we maintain constructive relations with our labor unions.
NUMBER OF EMPLOYEES
Number of employees % of employees covered under collective bargaining agreements % of employees covered under collective bargaining agreements expiring within one year
Sempra(1)
15,390 37 % 9 %
SDG&E 4,676 30 % 30 %
SoCalGas 8,178 53 % - %
(1) Excludes employees of equity method investees.
COMPANY WEBSITES
Company website addresses are:
▪Sempra - www.sempra.com
▪SDG&E - www.sdge.com
▪SoCalGas - www.socalgas.com
We make available free of charge on the Sempra website, and for SDG&E and SoCalGas, via a hyperlink on their websites, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.
The references to our websites in this report are not active hyperlinks and the information contained on, or that can be accessed through, the websites of Sempra, SDG&E and SoCalGas is not part of this report or any other report that we file with or furnish to the SEC and is not incorporated herein by reference.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
When evaluating our company and its subsidiaries 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 documents we file 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 in any forward-looking statements made by us or on our behalf, and the trading price of our securities and those of our subsidiaries could decline. These risk factors are not prioritized in order of importance or materiality, and they should be read in conjunction with the other information in this report, including the information set forth in the Consolidated Financial Statements and in “Part II - Item 7. MD&A.”
RISKS RELATED TO SEMPRA
Operational and Structural Risks
Sempra’s cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its subsidiaries and entities accounted for as equity method investments.
We are a holding company and substantially all our assets 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 cash flows 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, common and preferred dividends (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, court order 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. In addition, if Sempra is a creditor of any such entity, its rights as a creditor would be effectively subordinated to any security interest in the entity’s assets and any indebtedness of the entity senior to that held by Sempra. Sempra may elect to make capital contributions to its subsidiaries. Unlike a loan, there is no obligation for a subsidiary to repay a capital contribution to its parent, which cannot be accessed by the parent and becomes structurally subordinated to claims by creditors of the applicable subsidiary.
Sempra has substantial investments in and obligations arising from businesses it does not control or manage or in which it shares control.
We have and make investments in businesses we do not control or manage or in which we share control, including as a result of sales of a portion of our ownership interest in some of our businesses. 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 not always be in our interest and could negatively affect us. In addition, irrespective of whether or not we control these businesses, we could be responsible for liabilities or losses related to the businesses or elect to make capital contributions to these businesses during times of financial distress that could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. We discuss these investments further in Notes 5, 6 and 16 of the Notes to Consolidated Financial Statements.
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. Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our business could be negatively affected by actions of activist shareholders.
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 in high volumes could threaten our ability to use some or all of our NOL carryforwards if it results in our corporation undergoing an “ownership change” under applicable tax rules. Responding to activist shareholders could require us to incur legal and advisory fees, proxy solicitation expenses and administrative and associated costs and require time and attention by our board of directors and management, diverting their attention from the pursuit of our business strategies.
Any perceived uncertainties about our future direction or control, our ability to execute our strategies, or the composition of our board of directors or management team arising from activist shareholder attention or other action could lead to a perception of instability or a change in the direction of our business, which 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. Further, any such actions could cause fluctuations in the trading prices of our common stock, preferred stock and debt securities based on temporary or speculative market perceptions or other factors.
Financial and Capital Stock-Related Risks
Any impairment of our assets or investments could negatively impact us.
We could experience a reduction in the fair value of our assets, including our long-lived assets, intangible assets or goodwill, and/or 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, including any closure of the Aliso Canyon natural gas storage facility without adequate cost recovery, any inability to operate our existing facilities or develop new projects in Mexico due to proposed changes to existing 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 investment in capital projects that do not receive required approvals or are changed, abandoned or otherwise not completed. 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 18, 2022, we have 315,653,893 shares of our common stock and 900,000 shares of our non-convertible series C preferred stock outstanding. We may seek to raise capital by issuing additional equity 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.
Dividend requirements associated with 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 preferred stock, our common stock and our debt securities and would prohibit us, under the terms of the 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 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, whether or not consecutive, 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 for trading on the NYSE, our common stock is listed for trading on the Mexican Stock Exchange and registered with the CNBV. Such listing and registration subjects us to filing and other requirements in Mexico that could increase costs and increase performance risk of personnel given additional responsibilities. In addition, the CNBV, as the Mexican securities market regulator, has the authority to make inspections of Sempra’s business, primarily in the form of requests for information and documents; impose fines or other 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 information systems.
Our businesses own and operate electric transmission, distribution and storage facilities, natural gas transmission, distribution, regasification, liquefaction and storage facilities and other energy infrastructure, which are, in many cases, interconnected and/or managed by information technology systems. Even though our businesses undertake capital investment projects to construct, replace, maintain, improve and upgrade their respective facilities and information systems, there is a risk of, among other things, potential breakdown or failure of equipment or processes due to aging infrastructure and systems; human error; shortages of or delays in obtaining equipment, materials or labor; operational restrictions resulting from environmental requirements or governmental interventions; inability to enter into, maintain, extend or replace long-term supply contracts; and performance below expected levels, and these risks could be amplified while capital investment projects are in process. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could also be adversely affected by these or similar events occurring on the systems of such third parties, some of which may be unanticipated or uncontrollable by us.
Additional risks associated with the ability of our businesses to safely and reliably operate, maintain, improve and upgrade their respective facilities and systems, many of which are beyond our businesses’ control, include:
▪failure to meet customer demand for electricity and/or natural gas, including electrical blackout, curtailments or gas outages
▪natural gas surges into homes or other properties
▪the release of hazardous or toxic substances into the air, water or soil, including gas leaks
▪inadequate emergency preparedness plans and the failure to respond effectively to catastrophic events
The occurrence of any of these events could affect demand for electricity, natural gas or other forms of energy, cause unplanned outages, damage our businesses’ assets and/or operations, damage the assets and/or operations of third parties on which our businesses rely, damage property owned by customers or others, and cause personal injury or death. Any such outcome could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our businesses face risks related to the COVID-19 pandemic.
The COVID-19 pandemic has been materially impacting communities, supply chains, economies and markets around the world since March 2020. To date, the COVID-19 pandemic has not had a material impact on our results of operations. However, Sempra and some or all its businesses have been and could continue to be impacted by this pandemic or any future pandemic in a number of ways, including:
▪Implementing protocols and processes to comply with applicable government mandates related to virus exposure, testing and vaccination
▪Conducting business with substantial modifications to employee travel and work locations and virtualization of certain business activities, which could result in increased employee turnover or absenteeism, decreased efficiency and productivity and other similar affects that could increase operating costs and jeopardize our ability to satisfy compliance requirements and sustain operations
▪Disruption in the capital markets, which has affected and could further affect liquidity, strategic initiatives and prospects, including in some cases a slowdown of planned capital spending
▪Customer-protection measures implemented by SDG&E and SoCalGas, including suspending service disconnections due to nonpayment for all customers (except for SoCalGas’ noncore customers), waiving late payment fees, offering flexible payment plans and automatically enrolling residential and small business customers with past-due balances in long-term repayment plans, which have collectively resulted in a reduction in payments from SDG&E and SoCalGas’ customers and an increase in uncollectible accounts that could become material and may not be fully recoverable
▪Precautionary, preemptive and responsive actions taken by our current and prospective counterparties, customers and partners, as well as regulators and other governing bodies that affect our businesses, which have affected and could further affect our operations, results, liquidity and ability to pursue capital projects and strategic initiatives
Any of these impacts could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. We will continue to actively monitor the effects of the COVID-19 pandemic and may take further actions that alter our
business operations as may be required by federal, state or local authorities, or that we determine are necessary for the safety of our employees, customers, partners and suppliers and, generally, the communities we serve. However, we cannot at this time predict the extent to which the COVID-19 pandemic may further impact our businesses.
Severe weather, natural disasters and other similar events could materially adversely affect us.
Our facilities and infrastructure, including projects in development and under construction, may be damaged by severe weather, natural disasters, 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 may pose to our facilities and infrastructure, as well as the risks to the surrounding communities for which we could be held responsible, are substantially greater than the risks such incidents pose to a typical business.
Such incidents could result in business and project development disruptions, power outages, property damage, injuries and loss of life for which we could be liable 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 further 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 increase or become prohibitively expensive, be disputed by insurers, or become unavailable for certain of these risks or at sufficient 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, which could negatively impact construction projects and our ability to provide electricity and natural gas to customers. Moreover, weather-related incidents have become more prevalent, unpredictable and severe as a result of climate change or other factors, and we are currently experiencing a global pandemic, any of which 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 incident could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
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 difficulties in integrating acquired assets to our standards or in a timely manner or latent unforeseen defects. In addition, we may not realize all of the anticipated benefits from future acquisitions, partnerships or JVs such as increased earnings, cost savings, or revenue enhancements, for various reasons, including difficulties integrating operations and personnel, 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 new risks to our businesses.
We may periodically 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, energy storage, carbon sequestration, grid modernization and others. These activities and projects can 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. 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 recover or 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.
Several of our businesses have in place collective bargaining agreements with different labor unions, which are generally negotiated on a company-by-company basis. Any failure to negotiate and reach an agreement on these labor contracts could result in strikes, boycotts or other labor disruptions. Any such labor disruption or negotiated wage or benefit increases, whether due to
union activities, employee turnover or otherwise, could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
In addition to general information and cyber risks that all large corporations face, we face evolving cybersecurity risks associated with protecting sensitive and confidential customer and employee information and energy grid, natural gas pipeline, storage and other infrastructure.
Our businesses collect and retain sensitive information, including personal identification information about customers and employees, and our operations rely on complex, interconnected networks of generation, transmission, distribution, storage, control, and communication technologies and systems. Our use of business technologies, including deployment of any new technologies, represents a large-scale opportunity for attacks on or other failures to protect our information systems, confidential information and energy grid and natural gas infrastructure. In particular, cyber- and other attacks targeting utility systems and other energy infrastructures, as well as the impacts of these attacks on companies and their communities, are increasing in sophistication, magnitude and frequency and may further increase in the event of geopolitical events and other uncertainties, such as the conflict in Ukraine. Additionally, SDG&E and SoCalGas are increasingly required to disclose large amounts of data (including customer energy usage and personal information about customers) to support changes to California’s electricity market related to grid modernization and customer choice, increasing the risks of inadvertent disclosure or other unauthorized access of sensitive information. Further, the virtualization of many business activities during the COVID-19 pandemic increases cyber risk, and generally there has been an associated increase in targeted cyber-attacks. Moreover, all our businesses operating in California are subject to enhanced state privacy laws, which require companies that collect information about California residents to, among other things, make disclosures to consumers about their data collection, use and sharing practices; allow consumers to opt out of certain data sharing with third parties; and be liable under a new cause of action for breaches of certain highly sensitive personal information, and other states in which we do business could adopt similar laws.
Although we invest in risk management and information security measures for the protection of our systems and information, these measures could be insufficient or otherwise fail. The costs and operational consequences of implementing, maintaining and enhancing these protection measures are significant, and they could materially increase to address increasingly intense and complex cyber risks. We often rely on third-party vendors to deploy new business technologies and maintain, modify and update our systems, and these third parties may not have adequate risk management and information security measures with respect to their systems. Any cyber-attack, including ransomware attacks, on our or our vendors’ information systems or the integrity of the energy grid, our pipelines or our distribution, storage and other infrastructure, or unauthorized access, damage or improper disclosure of confidential information, could result in disruptions to our business operations, regulatory compliance failures, inabilities to produce accurate and timely financial statements, energy delivery failures, financial and reputational loss, customer dissatisfaction, litigation, violation of privacy 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 any or even a substantial portion of the costs associated with any 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 commercially reasonable.
Financial Risks
Our debt service obligations expose us to risks, and with respect to Sempra, could require additional equity securities issuances.
Our businesses have 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 for each of these businesses to service, pay or refinance their debts as they become due, particularly during adverse economic or industry conditions
▪limiting flexibility to pursue strategic opportunities or react to business developments or changes in the industry sectors in which they operate
▪requiring cash to be used for debt service payments, thereby reducing the cash available for other purposes
▪causing lenders to require materially adverse terms in the instruments for new debt, such as restrictions on uses of proceeds or other assets or limitations on incurring additional debt, creating liens, paying dividends, repurchasing stock, making investments or receiving distributions from subsidiaries or equity method investments
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 with the proceeds from issuances of equity securities. We may not be able to complete equity issuances on terms we consider acceptable or at all, and any new equity we do issue may dilute the voting rights and economic interests of existing holders of Sempra’s common and/or preferred stock. 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, and any such effects could materially adversely affect us.
Our businesses are capital-intensive. In general, we rely on long-term debt to fund a significant portion of our capital expenditures and repay outstanding debt and short-term borrowings to fund a significant portion of day-to-day business operations. Sempra may also seek to raise 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 or other negative effects on the terms of any debt or equity financing could cause us to fund operations and capital expenditures at a higher cost or fail to raise our targeted amount of funding, which could negatively impact our ability to meet contractual and other commitments, pursue development projects, make non-safety related capital expenditures and 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 the recent and proposed changes to the regulation of the energy market in Mexico
▪the overall health of the energy industry
▪volatility in electricity or natural gas prices
▪for Sempra, SDG&E and SoCalGas, 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
We are subject to risks due to uncertainty relating to the calculation of LIBOR and its scheduled discontinuance.
Certain of our financial and commercial agreements, including those for variable rate indebtedness, as well as interest rate derivatives, incorporate LIBOR as a benchmark for establishing certain rates. As directed by the U.S. Federal Reserve, banks ceased making new LIBOR-based issuances at the end of 2021, and publication of certain key U.S. dollar LIBOR tenors for existing loans is expected to cease in mid-2023. These events could cause LIBOR to perform differently than it has performed historically. Use of the Secured Overnight Financing Rate (SOFR), which has been identified as the replacement benchmark rate for LIBOR, may result in interest payments that are higher than expected or that do not otherwise correlate over time with the payments that would have been made using LIBOR. Changes to or the discontinuance of LIBOR, any uncertainty regarding such changes or discontinuance, and the performance and characteristics of alternative benchmark rates, could negatively affect our existing and future variable rate indebtedness and interest rate hedges and the cost of doing business under our commercial agreements that incorporate LIBOR, and could require us to seek to amend the terms of the relevant indebtedness or agreements, which may be materially worse than existing terms. 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.
Credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook.
Credit rating agencies routinely evaluate Sempra, SDG&E, SoCalGas and SI Partners and certain of our other businesses and their ratings are based on a number of factors, including the factors described below and the ability to generate cash flows; level of indebtedness; overall financial strength; specific transactions or events, such as share repurchases and significant litigation; the status of certain capital projects; and the state of the economy and our industry generally. These credit ratings could be downgraded, or other negative credit rating actions could occur at any time. We discuss these credit ratings further in “Part II - Item 7. MD&A - Capital Resources and Liquidity.”
For Sempra, Moody’s, S&P and Fitch (collectively, 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
▪Sempra’s consolidated financial measures do not improve, or it fails to meet certain financial credit metrics
▪catastrophic wildfires caused by SDG&E, or catastrophic wildfires caused 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 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 other California electric IOUs
▪a consistent weakening of SDG&E’s financial metrics or a deterioration in the regulatory environment
▪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, including a deterioration in the regulatory environment, leading to weakening of its stand-alone business risk profile
▪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
▪a ratings downgrade at Sempra
A downgrade of any of our businesses’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, may materially adversely affect the market prices of our equity and debt securities, the interest rates at which borrowings can be made and debt securities issued, and the various fees on credit facilities. This could make it more costly for the affected businesses to borrow money, issue equity or debt securities and/or raise other types of capital, any of which could materially adversely affect our ability to meet our debt obligations and contractual commitments, and 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, and for those contract positions that are hedged, our hedging procedures may not mitigate our risk as expected.
We may use forward contracts, physical purchase and sales contracts, futures, financial swaps and/or options, among others, to hedge our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity to try to reduce our financial exposure related to commodity price fluctuations. We do not hedge the entire exposure to market price volatility of our assets or our contract positions, and the extent of the coverage to these exposures varies over time. To the extent we have unhedged positions, or if our hedging strategies do not work as expected, fluctuating commodity prices could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Certain of the contracts we may use for hedging purposes are subject to fair value accounting, which may result in gains or losses in earnings for those contracts that may not reflect the associated gains or losses of the underlying position being hedged and could result in fluctuations of our results from period to period.
Risk management procedures may not prevent or mitigate losses.
Although we have in place 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 value-at-risk and loss limits, which are primarily based on historic price movements and which we discuss further 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 other postretirement benefit plans.
Sempra, SDG&E and SoCalGas provide defined benefit pension plans and other postretirement benefits 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
Our businesses require numerous permits, licenses, franchises and other approvals from various governmental agencies, and the failure to obtain or maintain any of them could materially adversely affect us.
Our businesses require numerous permits, licenses, rights-of-way, franchises, certificates and other approvals from federal, state, local and foreign governmental agencies. These approvals may not be granted in a timely manner or at all or may be modified, rescinded or fail to be extended for a variety of reasons. Obtaining or maintaining these approvals could result in higher costs or the imposition of conditions or restrictions on our operations. Further, these approvals require compliance by us and may require compliance by our customers, which could result in modification, suspension or rescission and subject us to fines and penalties if these requirements are not complied with. If one or more of these approvals were to be suspended, rescinded or otherwise terminated, including due to expiration or legal or regulatory changes, or modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise undesirable or impossible, 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.
We may 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 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 cause our costs to materially increase, result in material impairments, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our businesses are facing climate change concerns and have environmental compliance costs, which could have a material adverse effect on us.
Climate change and the costs that may be associated with its impacts have the potential to affect our businesses in many ways, including increasing the costs we incur in providing our services and the energy we transmit, impacting the demand for and consumption of our services and the energy we transmit (due to changes in both costs and weather patterns), and affecting the economic health of the regions in which we operate. Energy customers are also increasingly indicating preferences for carbon-neutral and renewable sources of energy.
Our businesses are subject to extensive federal, state, local and foreign statutes, orders, rules and regulations relating to environmental protection and climate change. To comply with these legal requirements, we must spend significant amounts on environmental monitoring and surveillance, pollution control equipment, mitigation costs and emissions fees, and these amounts could increase as a result of various factors we may not control, including if requirements change, enforcement of requirements increases, permits are not issued, renewed or amended as anticipated, energy demands increase or our mix of energy supplies changes. In addition, we may be responsible for on-site liabilities associated with the environmental and site condition of our projects and properties, regardless of when the liabilities arose and whether they are known or unknown, which exposes us to risks arising from contamination at our existing and former facilities and off-site waste disposal sites that have been used in our operations. For our regulated utilities, some of these costs may not be recoverable in rates. Failure to comply with environmental laws and regulations may subject our businesses to fines and penalties, including criminal penalties in some cases, and/or curtailments 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 and state-level environmental concerns and related new or proposed legislation and regulation or changes to existing legislation or regulation, such as increased requirements for monitoring and surveillance, pollution monitoring and control equipment, safety practices, emission fees, taxes, penalties or other obligations or restrictions, may have material negative effects on our operations, operating costs, corporate planning and the scope and economics of proposed expansions, infrastructure projects or other capital expenditures. In particular, existing and potential new or amended legislation and regulation relating to the control and reduction of GHG emissions and climate change may materially restrict our operations, negatively impact demand for our services and/or the energy we transmit, limit development opportunities, force costly or otherwise burdensome changes to our operations or otherwise materially adversely affect us. For example, SB 100 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, and 60% by 2030. SB 100 also creates the policy of meeting all of California’s retail
electricity supply with a mix of RPS Program-eligible and zero-carbon resources by 2045. The law also includes stipulations that this policy not increase carbon emissions elsewhere in the western grid and not allow resource shuffling, and requires that the CPUC, CEC, CARB and other state agencies incorporate this policy into all relevant planning. In addition to signing SB 100 into law, the then-Governor of California also 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.
Moreover, shifts in investor sentiment regarding fossil fuels is leading some to reduce investment in or divest from the sector completely. Maintaining investor confidence and attracting capital will be dependent on successfully demonstrating our ability to reduce emissions associated with our operations and the energy we transmit, consistent with our aim to have net-zero emissions by 2050. Our ability to reach net-zero emissions by 2050 depends on many factors, some of which we do not control, including supportive energy laws and policies, development and availability 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, and customer participation in conservation and energy efficiency programs. Although we have developed interim targets and various plans designed to support California in reaching its GHG emissions mandates, including SB 100, and our own energy goals, we may not be successful.
We will need to continue to make capital expenditures and incur costs to develop and deploy new technologies and modernize grid systems in our efforts to achieve our climate targets 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, the resulting rates or other costs to customers may 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 of our businesses could suffer reputational harm if we do not meet or scale back our GHG emissions goals or there are negative views about our environmental practices generally. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Our businesses are subject to numerous governmental regulations and complex tax and accounting requirements and may be materially adversely affected by these regulations or requirements or any changes to them.
The electric power and natural gas industries are subject to numerous governmental regulations, and our businesses are also subject to complex tax and accounting requirements. These regulations and requirements may undergo changes at the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these regulations and 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. 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 regulations and requirements could subject us to fines and penalties, including criminal penalties in some cases, and result in the temporary or permanent shutdown of certain facilities or operations. 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.
Our operations are subject to rules relating to transactions among SDG&E, SoCalGas and other Sempra businesses. These rules are commonly referred to as “affiliate rules,” and they primarily impact transmission supply, capacity, and marketing activities, including restricting our ability to sell natural gas or electricity to, or trade with, SDG&E and SoCalGas and its ability to effect these transactions with each other. 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.
We may be materially adversely affected by the outcome of litigation or other proceedings in which we are involved.
Our businesses are involved in a number of lawsuits, binding arbitrations and regulatory 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 and on related investigations and regulatory matters. 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 and effects of resolving these matters. In addition, juries have demonstrated a willingness to grant large awards, including punitive damages, in personal injury, product liability, property
damage and other claims. Accordingly, actual costs incurred may differ materially from insured or reserved amounts and may not be recoverable, in whole or in part, by insurance or in rates from customers. Any of the foregoing could cause reputational damage and 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 California (particularly SDG&E) and Sempra.
Potential for Increased and More Severe Wildfires
Over the past few years, California has been experiencing some of the largest wildfires (measured by acres burned) in its history. Frequent and more severe drought conditions, inconsistent and extreme swings in precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the intensity and prevalence of wildfires in California, including in SDG&E’s and SoCalGas’ service territories, and have made these wildfires increasingly difficult to prevent and contain. Changing weather patterns, including as a result of climate change, could cause these conditions to become even more extreme and unpredictable. These wildfires could jeopardize third-party property and SDG&E’s and SoCalGas’ electric and natural gas infrastructure 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 in the event of fires in these areas for which SDG&E or SoCalGas may be liable. Any such wildfires in SDG&E’s and SoCalGas’ territories 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 further detail in Note 1 of the Notes to Consolidated Financial Statements. The Wildfire Legislation’s revised 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, 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 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. 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, such as its electric distribution and transmission lines, is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including potential business interruption losses, and interest and attorneys’ fees, even if the utility has not been found negligent. The doctrine of inverse condemnation also is not exclusive of other theories of liability, including if the utility were found negligent, in which case 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 in the event that SDG&E’s equipment is determined to be a cause of a fire, and specifically in the context of the application of inverse condemnation. If a major fire is determined to be caused by SDG&E’s equipment, or if a major fire is determined to be caused by another participating IOU, and the Wildfire Fund is depleted as a result, Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
Cost Recovery Through Insurance or Rates
As a result of the strict liability standard applied to electric IOU-caused wildfires in California, substantial recent losses recorded by insurance companies, and the risk of an increase in the number and size of wildfires, obtaining insurance coverage for wildfires that could be caused by SDG&E or SoCalGas, particularly SDG&E, 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 challenged or unsuccessful when we seek recovery of increases in the cost of insurance 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 in sufficient amounts to meet the $1 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, such as the CPUC decision denying SDG&E’s recovery of costs related to wildfires in its service territory in 2007, 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 spend 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 applicable California law to submit annual 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 and fines or penalties for any failure to comply with the approved plans. One of our wildfire mitigation and safety tools is to de-energize certain of our facilities when certain weather conditions become extreme and there is elevated wildfire ignition risk. These “public safety power shutoffs” have been subject to scrutiny by various stakeholders, including customers, regulators and lawmakers, which could lead to legislation or rulemaking that increases the risk of penalties and 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 distributed energy resources, technological advancements, and political and regulatory developments.
Electric utilities in California are experiencing increasing deployment of distributed energy resources (DERs), such as solar generation, energy storage, energy efficiency and demand response technologies, and California’s environmental policy objectives are accelerating the pace and scope of these changes. This growth of DERs will require modernization of the electric distribution grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, enabling California’s clean energy goals will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options and electric vehicle infrastructure. The growth of the 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. The CPUC is conducting proceedings to evaluate various projects and pilots; implement changes to the planning and operation of the electric distribution grid to prepare for higher penetration of DERs; consider future grid modernization and grid investments; evaluate if traditional grid investments can be deferred by DERs; determine what, if any, compensation would be feasible and appropriate; and clarify the role of the electric distribution 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.
SDG&E provides bundled electric procurement service through various resources that are typically procured on a long-term basis. While SDG&E currently provides such procurement service for most of its customer load, some customers can 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. CCA is only available if a customer’s local jurisdiction (city) offers such a program and DA is currently limited by a cap based on gigawatt hours. A number of jurisdictions in SDG&E’s territory, including the City and County of San Diego and 14 other municipalities, have implemented, are implementing or are considering implementing CCA. Based on our current expectations, SDG&E could procure energy for less than half of its current customer load by December 31, 2022. SDG&E’s historical energy procurement may exceed the needs of its bundled customers as customers elect CCA and DA service. Accordingly, the associated costs of the utility’s procured resources could then be borne by SDG&E’s remaining bundled procurement customers. Existing state law requires that customers having CCA and DA procure their electricity must absorb the cost of above-market electricity procurement commitments already made by SDG&E on their behalf, which requirements are designed to equitably share costs among customers served by SDG&E and by CCA and DA. If adequate mechanisms are not implemented to help ensure compliance with this law, if the law changes, or if the law does not function as intended to achieve ratepayer indifference, remaining bundled customers of SDG&E 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 and natural gas storage have increasingly been the subject of political and public scrutiny, including a desire by some to reduce or eliminate reliance on natural gas as an energy source.
Certain California legislators and stakeholder, advocacy and activist groups 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 in lieu of the use of natural gas. Reducing methane emissions also has become a major focus of certain U.S. legislators and the current U.S. Administration. Certain California state agencies and city governments have proposed policies or passed ordinances to prohibit or restrict the use and consumption of natural gas in new buildings, appliances and other applications. These policies and ordinances and any other similar regulatory action could have the effect of reducing natural gas use over time. The CPUC has initiated an OIR to, among other things, implement a long-term planning strategy to manage the state’s transition away from natural gas-fueled technologies in an effort to meet California’s decarbonization goals. CARB, California’s primary regulator for GHG emissions reduction programs, continues to pursue plans for reducing GHG emissions in line with California’s climate goals that include proposals to reduce natural gas demand, including more aggressive energy efficiency programs, increased renewable electric generation and replacement of natural gas appliances with electric appliances. A substantial reduction in, or the elimination of, natural gas as an energy source in California could have a material adverse effect on SoCalGas’, SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects, including 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, required to be depreciated on an accelerated basis or become stranded, without adequate recovery of and on the investments.
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 further 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 have been generally 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 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 SONGS 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 by federal, state and local legislative and regulatory authorities, which may materially adversely affect Sempra, SDG&E and SoCalGas.
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, as well as its 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 also 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 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; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of regulators, consumer and other stakeholder groups and customers. These ratemaking proceedings include decisions about major programs in which SDG&E and SoCalGas make investments under an approved CPUC framework, but which investments may remain subject to a CPUC filing or reasonableness review with unclear standards that may result in the disallowance of incurred costs. SDG&E and SoCalGas also may be required to incur costs and make investments to comply with proposed legislative and regulatory requirements and initiatives, including those related to California’s climate goals and policies, and its ability to recover these costs and investments may depend on the final form of the legislative or regulatory requirements and the ratemaking mechanisms associated with them. Recovery can also be affected by the timing and process of the ratemaking mechanism in which there can be a significant time lag between when costs are incurred and when those costs are recovered in customers’ rates and material differences between the forecasted and authorized costs embedded in rates (which are set on a prospective basis) and the actual costs incurred. The CPUC may also experience delays in its decisions on recovery or may deny recovery altogether on the basis that costs were not reasonably or prudently incurred or for other reasons. Any of these outcomes could materially adversely affect SDG&E’s and SoCalGas’ rates and its and Sempra’s results of operations, financial condition, cash flows and/or prospects.
In addition, under the CPUC’s cost of capital framework, SDG&E and SoCalGas are required to file new cost of capital applications every three years. SDG&E’s and SoCalGas’ cost of capital are then assessed in the intervening years through the CCM. The CCM, if triggered by changes in key benchmark interest rates, automatically updates SDG&E’s or SoCalGas’, as applicable, authorized rates of return for that year. For the 12-months ended September 30, 2021, SoCalGas did not trigger the CCM, while SDG&E exceeded its benchmark rate, which would trigger the CCM. The CPUC alternatively provides that SDG&E and SoCalGas each has the right to have its cost of capital assessed through an application based on an extraordinary or catastrophic event that materially impacts its cost of capital and affect utilities differently than the market as a whole. If the CPUC finds that the conditions are met to file such an application, the CCM would not apply. SDG&E has filed an application to have its cost of capital for 2022 assessed through a cost of capital proceeding based on the extraordinary events of the COVID-19 pandemic, rather than have the CCM applied. The CPUC has established a proceeding to determine if SDG&E’s cost of capital was impacted by an extraordinary event. If the CPUC finds that there was not an extraordinary event, the CCM trigger for SDG&E could materially adversely affect the results of operations, financial condition, cash flows and/or prospects of Sempra and SDG&E. If the CPUC finds that there was an extraordinary event, it will then determine whether to suspend the CCM for 2022 and preserve SDG&E’s current authorized cost of capital or hold a second phase of the proceeding to set a new cost of capital for 2022. We further discuss the CCM, including the impact of SDG&E’s trigger of the CCM in the most recent measurement period, 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.
CPUC Authority Over Operational Matters
The CPUC has regulatory authority related to safety standards and practices, competitive conditions, reliability and planning, affiliate relationships and a wide range of other operational matters, including citation programs concerning matters such as safety activity, disconnection and billing practices, resource adequacy and environmental compliance. For example, in June 2019, the CPUC opened an OII to determine whether SoCalGas’ and Sempra’s organizational culture and governance prioritize safety. Phase 1 of the OII involved a CPUC consultant producing a report that evaluates organizational culture, governance, policies, practices, and accountability metrics in relation to operations, including record of safety incidents. In January 2022, the CPUC issued a ruling initiating Phase 2 activities and entering the Phase 1 consultant’s report into the record. Consistent with the recommendations of the Phase 1 consultant’s report, the ruling indicates that Phase 2 will focus on constructive, forward-looking actions intended to improve safety outcomes in the future. Many of these standards and programs are becoming more stringent and could impose severe penalties, including enforcement programs under which the CPUC staff can issue citations that in some cases can impose substantial fines. The CPUC conducts reviews and audits of the matters under its authority and could launch investigations or open proceedings at any time on any such matter it deems appropriate, the results of which could lead to citations, disallowances, fines and penalties, as well as corrective or mitigation actions required to address any noncompliance that may not be sufficiently funded in customer rates or at all. Any such occurrence could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
We discuss various CPUC proceedings relating to SDG&E and SoCalGas in Notes 4, 15 and 16 of the Notes to Consolidated Financial Statements.
Influence of Other Organizations and Potential Regulatory Changes
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 regulatory bodies with authority over our operations 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, a substantial portion of which may not be recoverable through insurance.
From October 23, 2015 through February 11, 2016, SoCalGas experienced a natural gas leak from one of the injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility in Los Angeles County. As further described in Note 16 of the Notes to Consolidated Financial Statements, numerous lawsuits, investigations and regulatory proceedings have been initiated in response to the Leak, resulting in significant costs.
Civil Litigation
As of February 18, 2022, approximately 390 lawsuits, including approximately 36,000 plaintiffs, two consolidated class action complaints, claims for violations of Proposition 65 and shareholder derivative actions are pending against SoCalGas related to the Leak, some of which have also named Sempra and/or certain officers and directors of SoCalGas and Sempra. Additional litigation, including by public entities, or criminal complaints may be filed against us related to the Leak or our responses to it. All pending cases are coordinated before a single court in the LA Superior Court for pretrial management. Most of the lawsuits are the subject of an agreement entered into in September 2021 that would result in dismissal of the claims therein and releases by all participating plaintiffs of SoCalGas, Sempra and their respective affiliates from all claims related to the Leak. However, this agreement is subject to various conditions to effectiveness, including a minimum participation rate by the applicable plaintiffs and approvals by the LA Superior Court, which may not be satisfied. If these conditions are not satisfied, then the agreement will not become effective and all lawsuits subject to the agreement will remain pending. If these conditions are satisfied, then SoCalGas will be required to make payments of up to $1.8 billion to the participating plaintiffs. The two class action complaints are the subject of agreements also entered into in September 2021 that would result in dismissal of the claims therein and releases by plaintiffs and class members. One of these agreements requires approvals by the LA Superior Court, which may not be satisfied, in which case the complaint will remain pending. If the settlement is approved, then SoCalGas will be required to pay $40 million to a class of property owners. Sempra elected to make an $800 million equity contribution to SoCalGas in September 2021 and may elect to make additional equity contributions in the future that are intended to maintain SoCalGas’ approved capital structure in connection with the accruals related to these agreements. Such amounts, as well as the costs of defending against or settling or otherwise resolving the remaining pending lawsuits, including any lawsuits filed by plaintiffs or class or putative class members who do not agree to settle under or opt out of the agreements described above, and any compensatory, statutory or punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, could materially adversely affect SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects. We discuss these risks further above under “Risks Related to All Sempra Businesses - Legal and Regulatory Risks” and in this risk factor below under “Insurance and Estimated Costs.”
Governmental Investigations, Orders and Additional Regulation
In June 2019, the CPUC opened an OII to consider penalties against SoCalGas for the Leak. The first phase will consider, among other things, whether SoCalGas violated applicable laws, CPUC orders or decisions, rules or requirements and whether SoCalGas engaged in unreasonable and/or imprudent practices with respect to its operation and maintenance of the Aliso Canyon natural gas storage facility or its related record-keeping practices. The SED has alleged hundreds of violations in this first phase, asserting that SoCalGas violated California Public Utilities Code Section 451 and failed to cooperate in the investigation and to keep proper records. The second phase will consider whether SoCalGas should be sanctioned for the Leak and what damages, fines or other penalties, if any, should be imposed for any violations, unreasonable or imprudent practices, or failure to sufficiently cooperate with the SED as determined by the CPUC in the first phase. In addition, the second phase will determine the ratemaking treatment or other disposition of costs incurred by SoCalGas in connection with the Leak, which could result in little or no recovery of such costs. SoCalGas has engaged in settlement discussions with the SED in connection with this proceeding.
This OII and other investigations into the Leak could result in findings of violations of laws, orders, rules or regulations as well as fines and penalties, any of which could involve substantial costs and cause reputational damage. In addition, SoCalGas may incur higher operating costs and additional capital expenditures as a result of these investigations or new laws, orders, rules and regulations arising out of this incident, or our responses thereto, which may not be recoverable through insurance or in customer rates. The occurrence of any of these risks could materially adversely affect SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Natural Gas Storage Operations and Reliability
In February 2017, the CPUC opened a proceeding pursuant to 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 considering 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, the facility could be impaired, higher than expected operating costs could be incurred and/or additional capital expenditures may be required, 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.
Insurance and Estimated Costs
At December 31, 2021, SoCalGas estimates certain costs related to the Leak are $3,221 million (the cost estimate), which includes the $1,279 million of costs recovered or probable of recovery from insurance. This cost estimate may increase significantly as more information becomes available. A portion of the cost estimate has been paid, and $1,983 million is accrued as Reserve for Aliso Canyon Costs at December 31, 2021 on SoCalGas’ and Sempra’s Consolidated Balance Sheets.
The civil litigation against us related to the Leak seeks compensatory, statutory and punitive damages, restitution, and civil and administrative fines, penalties and other costs. We also could be subject to damages, fines or other penalties as a result of the pending regulatory investigations and other matters related to the Leak. Except for the amounts paid or estimated to settle certain legal and regulatory matters as described above, the cost estimate does not include litigation, regulatory proceedings or other matters to the extent it is not possible to predict at this time the outcome of these actions or reasonably estimate the possible costs or a range of possible costs for damages, restitution, civil or administrative fines or penalties, defense, settlement or other costs or remedies that may be imposed or incurred. The cost estimate also does not include certain other costs incurred by Sempra associated with defending against shareholder derivative lawsuits and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Further, we are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued. These costs or losses not included in the cost estimate 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.
We have received insurance payments for many of the categories of costs included in the cost estimate, and we intend to pursue the full extent of our insurance coverage for the costs we have incurred. Other than insurance for certain future defense costs we may incur as well as directors’ and officers’ liability, we have exhausted all of our insurance in this matter. We continue to pursue other sources of insurance coverage for costs related to this matter, but we may not be successful in obtaining additional insurance recovery for any of these costs. If we are not able to secure additional insurance recovery, if any costs we have recorded as an insurance receivable are not collected, if there are delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes while the associated costs are not tax deductible, such amounts, which could be significant, 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 rate structure could have a material adverse effect on 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. Under the current mechanism, NEM customers receive a full 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. As of December 31, 2021, the CPUC has declined to adopt a fixed charge independent of consumption volume for residential customers. However, it has advised the utilities to renew their requests for a fixed charge at a later date if such proposals include an adequate customer outreach and communications plan. In August 2020, the CPUC initiated a rulemaking to further develop a successor to the existing NEM tariff. In December 2021, a proposed decision was issued recommending substantial reform of the NEM program through the establishment of a new Net Billing Tariff that would apply to new net metered customers. The new Net Billing Tariff is intended to provide for the payment by new net metered customers of their proportionate share of maintaining and operating the electric transmission and distribution system, which, if the proposed decision is adopted, should reduce the cost-shifting burden from new net metered customers to non-NEM customers. The timing of the final decision is uncertain. Depending on the structure and functionality of the Net Billing Tariff, which is uncertain, the risks associated with the existing NEM tariff 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, as well as the progression of distributed energy resources and 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 fails to adequately reform SDG&E’s 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 a majority of its 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
▪Oncor will not pay dividends or other distributions (except for contractual tax payments) if that payment would cause its debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT
▪if Oncor’s senior secured debt credit rating by any of the Rating Agencies falls below BBB (or Baa2 for Moody’s), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT
▪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 stock 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 such budget is more than a 10% increase or decrease from the corresponding amounts in the budget for the preceding fiscal year or multi-year period, as applicable
▪Sempra must continue to hold indirectly at least 51% of the ownership interests in Oncor Holdings and Oncor until at least March 9, 2023, unless otherwise authorized by the PUCT
As a result of these measures, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate matters. We have limited representation on the Oncor Holdings and Oncor boards of directors, which are each controlled by independent directors. 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 certain cases be contrary to our interests. To the extent the directors approve or Oncor otherwise pursues actions that are not in our interests, our results of operations, financial condition, cash flows and/or prospects may be materially adversely affected.
Industry-Related Risks
Changes in the regulation or operation of the electric utility industry and/or the ERCOT market could materially adversely affect Oncor, which could materially adversely affect us.
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.” In particular, 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, Oncor operates in the ERCOT market and, as a result, any economic weakness or reduced electricity demand in ERCOT 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, including temporary measures such as the approximately four-month long moratorium on customer disconnections due to nonpayment that was in place following an extreme winter weather event and resulting power outages in February 2021, other actions taken by governmental authorities, customers or other third parties to address financial challenges following this event or other similar events, legislation affecting the ERCOT market to address issues with its operation during this event or other similar events or to improve grid reliability generally, or the growth of third-party distributed energy resources and other technologies that may increasingly compete with Oncor’s traditional transmission and distribution infrastructure in delivering electricity to consumers. If Oncor does not successfully respond to any such changes applicable to it, 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’s operations are capital-intensive, and it could have liquidity needs that necessitate additional investments.
Oncor’s business is capital-intensive, 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 in the future. Because our commitments to the PUCT prohibit us from making loans to Oncor, we may elect to make additional capital contributions if Oncor fails to meet its capital requirements or is unable to access sufficient capital to finance its ongoing needs. Any such investments could be substantial, would reduce the cash available to us for other purposes, 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 from EFH 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 IRC (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, now Sempra Texas Holdings Corp. and a subsidiary of Sempra. 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 and potentially eliminate the value associated with our indirect investment in Oncor and could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects and the market value of its common stock, preferred stock and debt securities.
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, any of which could materially adversely affect us.
All Energy Infrastructure Projects
We are involved in a number of energy infrastructure projects, which subject us to numerous risks. Success in developing such a project is contingent upon, among other things:
▪our financial condition and cash flows and other factors that impact our ability to invest sufficient funds into the project, including for preliminary matters that may need to be accomplished before we can 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, including, as applicable, by all project partners, and many of the other factors described in this risk factor
▪negotiation of satisfactory EPC agreements, including any renegotiation that may be required in the event of delays in final investment decisions or other failures to meet specified deadlines
▪progressing relationships from MOUs or similar arrangements, which are nonbinding and generally do not impose obligations on any of the parties, to execution of definitive agreements and participation in the project
▪identification of suitable partners, customers, suppliers and other necessary counterparties, negotiation 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 final investment decision within agreed timelines
▪timely receipt and maintenance of required governmental permits, licenses and other authorizations that do not impose material conditions and are otherwise granted under terms we find reasonable
▪our project partners’, contractors’ and other 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, equipment unavailability, contractor performance 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 adequate and reasonably priced financing for the project
▪the absence of hidden defects or inherited environmental liabilities for any project construction
▪fast and cost-effective resolution of any litigation or unsettled property rights affecting the project
▪geopolitical events and other uncertainties, such as the conflict in Ukraine
Any failures with respect to the above factors or other factors material to any particular project could involve additional costs and 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 never recover or receive an adequate or any return on our investment and other resources invested in 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 are able to complete involves many risks, including the potential for unforeseen design flaws, engineering challenges, equipment failures or the breakdown for other reasons of facilities, equipment or processes; labor disputes; fuel interruption; environmental contamination; 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 our facilities 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 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 such a decision is reached and a project is completed, the overall success of the project are dependent on global energy markets, including natural gas and oil supply, demand and pricing. In general, depressed natural gas and LNG prices in the markets we intend to serve due to shifts in supply or other factors 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. A reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, or as a result of calls by some to limit or eliminate reliance on natural gas as an energy source globally. Oil prices could also 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 any available LNG demand. Any of these developments 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 proposed projects may face distinct disadvantages relative to some other LNG projects under construction or in development by other project developers, including:
▪The proposed expansion of the Cameron LNG JV facility (Phase 2) is subject to certain restrictions and conditions under the financing agreements for Phase 1 of the project and requires unanimous consent of all JV partners, including with respect to the equity investment obligations of each partner. We may not be able to satisfy these conditions and requirements, in which case our ability to develop the Phase 2 project would be jeopardized.
▪Our Port Arthur, Texas project is a greenfield site and therefore is subject to disadvantages relative to brownfield sites, including increased time and costs to develop and construct the project.
▪The ECA LNG projects 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 Risks.” In addition, the Mexican regulatory process and overlay of U.S. regulations for natural gas exports to LNG facilities in Mexico are not well developed, which, among other factors, contributed to delays obtaining a necessary permit from the Mexican government and reaching a final investment decision 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. We have entered into contracts with affiliates and third parties, subject to certain conditions, to supply and transport gas to and across the U.S.-Mexico border to meet the requirements of the ECA LNG Phase 1 project if and when it becomes operational. If affiliates or third parties experience any delays or fail to obtain and maintain necessary permits and arrangements to provide such supply or transportation service or if we fail to maintain adequate gas supply and transportation agreements to support the project fully, it
could cause additional costs or delays to the ECA LNG Phase 1 project. Finally, although we have planned measures to not disrupt operations at the ECA Regas Facility with the construction or operation of the ECA LNG Phase 1 project, we expect construction of the proposed ECA LNG Phase 2 project would conflict with ECA Regas Facility operations, making the decision on whether and how to pursue the ECA LNG Phase 2 project dependent in part on whether the investment in this large-scale liquefaction export facility would, over the long term, be more beneficial than continuing to provide regasification services under existing contracts for 100% of the ECA Regas Facility’s capacity through 2028.
Development of additional trains and liquefaction facilities will depend on the ability of our existing pipeline interconnections to be expanded 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. We and third parties may not be able to successfully develop and construct such new pipeline facilities, or we may not be able to secure such additional pipeline interconnections on commercially reasonable terms or at all.
The capital requirements for natural gas liquefaction and LNG export projects that we have decided, or may in the future decide, to proceed with can be significant. 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 facilities could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Financing Arrangements
We may become involved in various financing arrangements with respect to any of our energy infrastructure projects, such as guarantees, indemnities or 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, that could have a material adverse effect on our future results of operations, financial condition, cash flows and/or prospects.
We are dependent on the equipment provided by third parties to operate Cameron LNG JV’s Phase 1 project and the failure of such equipment may adversely impact our business and performance.
Cameron LNG JV has experienced operating issues with equipment provided by certain third-party vendors, which have caused reductions in operating capacity and the declaration of force majeure events by Cameron LNG JV under its tolling agreements. Certain of Cameron LNG JV’s customers have raised objections regarding these force majeure declarations, and Cameron LNG JV’s customers may raise objections in the future regarding these declarations or other force majeure declarations for similar operating issues. Cameron LNG JV’s customers have rights under their tolling agreements to obtain certain future quantities of excess LNG production in connection with these and certain other force majeure events, and future force majeure events may also lead to the additional accrual of similar rights. The requirement to deliver excess LNG production to these customers in connection with these force majeure events has had, and in the future could have, an adverse impact to Sempra Infrastructure’s and our business and cash flows as Cameron LNG JV loses fees related to the excess production.
These and other operational issues arising from equipment or facilities provided by third-party vendors may require us to undertake remediation, repair or equipment replacement activities in the future that could result in reductions or cessations in production from our facilities. Although we are seeking to enforce warranty and other claims against our EPC contractors and other equipment vendors and suppliers, we may face challenges in successfully enforcing these claims against these third parties. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Hydraulic fracturing is subject to political, economic and other uncertainties.
Domestic and international hydraulic fracturing operations face political and economic risks and uncertainties. Several states have imposed or are considering imposing more stringent permitting, public disclosure and well construction requirements, and some local municipalities have adopted or are considering adopting land use restrictions that may restrict or prohibit well drilling in general and/or hydraulic fracturing in particular. We cannot predict whether additional federal, state, local or international laws or regulations applicable to hydraulic fracturing will be enacted and, if so, what actions any such laws or regulations would require or prohibit. The current U.S. Administration may have a negative view of hydraulic fracturing, which could increase the risk of regulation that negatively affects these operations. If additional regulation or permitting requirements are imposed on domestic hydraulic fracturing operations, natural gas prices in North America could rise and the relative pricing advantage in favor of domestic natural gas could decline, which could materially adversely affect demand for LNG exports and our ability to develop commercially viable LNG export facilities beyond Cameron LNG JV Phase 1 and ECA LNG Phase 1 (which are fully contracted). Any such occurrence could materially adversely affect our 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 with customers 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. If these contracts are at fixed prices, 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 may 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.
Increased competition could materially adversely affect us.
The markets in which we operate are characterized by numerous strong and capable competitors, many of whom 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. In addition, our Mexican natural gas distribution business faces increased competition now that its former exclusivity period with respect to its distribution zones has expired and other distributors are legally permitted to build and operate natural gas distribution systems and compete to attract customers in the locations where it operates. 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 capacity agreements with three counterparties that collectively subscribe for the full nameplate capacity of its Phase 1 facility. 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 the long-term nature of our relationships with these counterparties. We are currently engaged in a legal dispute with the two third-party capacity customers, Shell Mexico and Gazprom, at the ECA Regas Facility involving breach of contract claims, a constitutional challenge of the CRE’s approval of the general terms and conditions for service at the facility, and proceedings seeking to modify or revoke certain material permits needed by the facility and the proposed ECA LNG projects. We discuss this dispute in Note 16 of the Notes to Consolidated Financial Statements. These challenges and proceedings or any similar or other issues that arise with respect to these or our other long-term contracts, including the conflict in Ukraine, 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 is dependent 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 or sell it at favorable prices, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our businesses depend on the performance of counterparties, and any performance failures by these counterparties could materially adversely affect us.
Our businesses depend on business partners, customers, suppliers and other counterparties who owe money or commodities as a result of market transactions or other long-term arrangements to perform their obligations in accordance with such arrangements. Should they fail to perform, we may need to enter into alternative arrangements or honor our underlying commitments at then-
current market prices, which may result in additional losses to us to the extent of amounts already paid to such counterparties. 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 may not be successful. In addition, many such 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 partners, customers or suppliers at all or on terms at least as favorable to the original terms if any of these agreements 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 presents 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.
Sempra Infrastructure’s obligations and those of its LNG suppliers are contractually subject to suspension or termination for “force majeure” events, which generally are beyond the control of the parties, and limitations of remedies for other failures to perform, including limitations on damages that may prohibit recovery of all 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. We discuss the risks related to these arrangements above under “Risks Related to Sempra - Operational and Structural Risks.”
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 natural gas liquefaction export facilities
▪supply natural gas to our gas storage and electric generation facilities
▪provide retail energy services to customers
If transportation is disrupted, if the construction of new or modified interconnecting infrastructure is not completed on schedule or if capacity is inadequate, we may not be able to move forward with our projects on schedule, we may be unable to sell and deliver our commodities, electricity and other services to our customers, we may be responsible for damages incurred by these customers, 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 in competitive market conditions. 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 and inflation risks.
Our operations in Mexico pose foreign currency and inflation risks. Exchange and inflation rates with respect to the Mexican peso and fluctuations in those rates may have an impact on the revenue, costs and cash flows 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 successfully 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 market risks, including fluctuations in commodity prices, that could materially adversely affect us.
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 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.
Overview
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:
▪tax, trade, environmental and other foreign laws and regulations and compliance with them, 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 to or difficulty obtaining, maintaining and complying with permits or approvals; difficulty enforcing contractual and property rights; differing legal standards for lawsuits or other proceedings; and unsettled property rights and titles in Mexico
▪expropriation or theft of assets
▪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 has exercised, and continues to exercise, significant and increasing influence over the Mexican economy and energy sector and is proposing additional changes that, in each case, could fundamentally impact private investment in this sector.
With respect to the electricity market, the Mexican legislature is currently considering proposed constitutional reform that would, among other things, make the CFE the only entity allowed to commercialize electric energy in Mexico, thereby eliminating the wholesale electricity market entirely. This reform would also limit the overall capacity and types of plants eligible to generate electricity for the CFE to commercialize, resulting in the cancelation of electricity generation permits and contracts for the sale of electricity to the CFE, including permits at all of Sempra Infrastructure’s operational power generation facilities. Recent Mexican governmental actions in the electricity market also include resolutions, orders, decrees, regulations and proposed 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.
With respect to midstream and downstream activities, recent governmental actions include amendments in June, October, and November of 2021 to Mexico’s General Foreign Trade Rules that establish additional requirements for obtaining authorizations for the import and export of hydrocarbons, refined products, petrochemicals, and biofuels through channels other than those authorized (LDA authorizations). The ECA Regas Facility and the Veracruz terminal have LDA authorizations that are valid through 2023, although the ability to subsequently renew these authorizations may be limited by these amended rules. We are assessing the effect of these amended rules on our operations and development of future projects, including those in the vicinity of Topolobampo, Manzanillo and Ensenada, as well as the proposed ECA LNG liquefaction projects. In addition, amendments to Mexico’s Hydrocarbons Law that give SENER and the CRE additional powers to suspend and revoke permits were published in May 2021. While the courts have enjoined enforcement of these amendments pending a final disposition in the case of several of our projects, the amendments provide that suspension of permits will be determined by SENER or the CRE when a danger to national security, energy security, or the national economy is foreseen, and also provide new grounds for the revocation of permits under certain circumstances. Additionally, in the case of existing permits, the amendments direct authorities to revoke permits that
fail to comply with the minimum storage requirements established by SENER or fail to comply with requirements or violate provisions established by the amended Hydrocarbons Law.
Finally, as part of an industrywide audit and investigative process initiated by the CRE to enforce fuel procurement laws, federal prosecutors conducted inspections at several refined products terminals, including Sempra Infrastructure’s refined products terminal in Puebla, to confirm that the gasoline and/or diesel in storage were legally imported. During the inspection of the Puebla terminal in September 2021, a federal prosecutor took samples from all the train and storage tanks in the terminal and ordered that the facility be temporarily shut down during the pendency of the analysis of the samples and investigation, while leaving the terminal in Sempra Infrastructure’s custody. In addition, in November 2021, the CRE notified Sempra Infrastructure of the commencement of an administrative proceeding for revoking the storage permit at the Puebla terminal due to alleged breach of its terms and conditions. We cannot predict when the investigation will be completed, the outcome of the administrative proceeding or whether and/or when the facility will be able to commence commercial operations.
We discuss these Mexican governmental actions further in Note 16 of the Notes to Consolidated Financial Statements. We cannot predict whether proposed changes like the constitutional reform to the electricity market or other similar governmental actions will ultimately be passed or otherwise become effective in their current forms, nor can we predict the nature or level of impact of this constitutional reform on non-electric segments of the energy sector. We also cannot predict whether actions to enjoin enforcement or suspend or overturn existing laws and other governmental actions will be successful. More generally, we cannot predict the impact that the political, social, and judicial landscape in Mexico will have on that country’s economy and energy sector and our business in Mexico. If any of the recent Mexican governmental actions are passed or otherwise become effective, if efforts to enjoin their enforcement or suspend or overturn them fail, or if other similar moves by the Mexican government are taken to curb private-party participation in the energy sector, including the passage of additional laws or regulations or increased investigative and enforcement activities, this could materially 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, 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 our business, results of operations, financial condition, cash flows and/or prospects.
U.S. and Mexican Laws and Foreign Policy, including Trade and Related Matters
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 increase the adverse effects on our businesses and create uncertainty, making it difficult to predict the impact these policies could have 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 economies and foreign companies with whom we conduct business, could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our businesses are subject to various legal actions challenging our property rights and permits, and our properties in Mexico could be subject to expropriation by the Mexican government.
We are engaged in disputes regarding our title to the property in Mexico where our ECA Regas Facility is situated and our proposed 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 located on land we do not own for a specific period of time. If we are unable to defend and retain title to the properties we own or if we are unable to obtain or retain rights to construct and operate on the properties we do not own on reasonable financial and other terms, we could lose our rights to occupy and use these properties and the related facilities, which could delay or derail proposed projects, increase our development costs, and result in breaches of one or more permits or contracts related to the affected facilities that could lead to legal costs, fines or penalties. In addition, disputes regarding 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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
We own or lease land, warehouses, offices, operating and maintenance centers, shops and service facilities necessary to conduct our businesses. Each of our operating segments currently has adequate space and, if we needed 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.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters described in Notes 15 and 16 of the Notes to Consolidated Financial Statements, “Part I - Item 1A. Risk Factors” and “Part II - Item 7. MD&A.”

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II.

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION
Sempra Common Stock
Our common stock is traded on the NYSE under the trading symbol SRE and the Mexican Stock Exchange under the trading symbol SRE.MX. At February 18, 2022, there were approximately 22,180 record holders of our common stock.
SoCalGas and SDG&E Common Stock
Information concerning dividend declarations for SoCalGas and SDG&E is included in “Part II - Item 7. MD&A - Capital Resources and Liquidity - Sources and Uses of Cash - Dividends.”
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $2 billion or amounts spent to purchase no more than 25 million shares. This repurchase authorization was publicly announced on August 5, 2020 and has no expiration date.
The following table sets forth information about our common stock repurchase activity for the three months ended December 31, 2021:
PURCHASES OF EQUITY SECURITIES
(Dollars in millions, except per share amounts)
Total number of shares purchased(1)
Average price paid per share(1)(2)
Total number of shares purchased as part of publicly announced plans or programs(1)
Maximum dollar value of shares that may yet be purchased under the plans or programs
November 1, 2021 - November 30, 2021 1,525,000 $ 123.91 1,525,000 $ 1,811
December 1, 2021 - December 31, 2021 897,758 $ 123.69 897,758 $ 1,700
Total 2,422,758 $ 123.83 2,422,758 $ 1,700
(1) All share purchases were made through open market repurchases.
(2) The price per share reflects the weighted-average price paid per share during the applicable period, and excludes amounts paid for broker fees, commissions and other similar costs.
In addition on January 11, 2022, we entered into an ASR program under which we prepaid $200 million to repurchase shares of our common stock in a share forward transaction. A total of 1,472,756 shares were purchased under this program, which was determined by dividing the $200 million purchase price by the arithmetic average of the volume-weighted average trading prices of shares of our common stock during the valuation period of January 12, 2022 through February 11, 2022, minus a fixed discount. The ASR program was completed on February 11, 2022. As of February 25, 2022, a maximum of $1.5 billion and no more than 21,104,486 shares may yet be purchased under the repurchase authorization that was publicly announced on August 5, 2020.
We may also, from time to time, purchase shares of our common stock to which participants would otherwise be entitled from LTIP participants who elect to sell a sufficient number of shares in connection with the vesting of RSUs and stock options in order to satisfy minimum statutory tax withholding requirements.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. (RESERVED)
Not applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
In 2018, we set out to simplify Sempra’s business model and sharpen our focus on our mission to be North America’s premier energy infrastructure company. Our 2021 operational and financial results reflect our focus on executing this strategy:
▪We completed the consolidation of our non-utility, energy infrastructure assets in North America under SI Partners
▪We completed the sale of a 20% NCI in SI Partners to KKR
▪We entered into an agreement to sell an additional 10% NCI in SI Partners to ADIA
▪We invested $5.6 billion in capital expenditures and investments
In the fourth quarter of 2021, we formed Sempra Infrastructure, a new segment that includes the operating companies of our subsidiary, SI Partners, as well as a holding company and certain services companies. Sempra Infrastructure develops, builds, operates and invests in energy infrastructure to help enable the energy transition in North American markets and globally.
Our former South American businesses and certain activities associated with those businesses are presented as discontinued operations. Nominal activities that are not classified as discontinued operations have been subsumed into Parent and other. We completed the sales of these businesses in the second quarter of 2020. Our discussions below exclude discontinued operations, unless otherwise noted.
RESULTS OF OPERATIONS
We discuss the following in Results of Operations:
▪Overall results of operations of Sempra;
▪Segment results;
▪Significant changes in revenues, costs and earnings; and
▪Impact of foreign currency and inflation rates on our results of operations.
OVERALL RESULTS OF OPERATIONS OF SEMPRA
OVERALL RESULTS OF OPERATIONS OF SEMPRA
(Dollars, except per share amounts; shares in millions)
Our earnings and diluted EPS were impacted by variances discussed below in “Segment Results.”
SEGMENT RESULTS
This section presents earnings (losses) by Sempra segment, as well as Parent and other and discontinued operations, and a related discussion of the changes in segment earnings (losses). Throughout the MD&A, our reference to earnings represents 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 NCI, where applicable.
SEMPRA EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
Years ended December 31,
2021 2020 2019
SDG&E $ 819 $ 824 $ 767
SoCalGas (427) 504 641
Sempra Texas Utilities 616 579 528
Sempra Infrastructure 682 580 247
Sempra Renewables - - 59
Parent and other(1)
(436) (563) (515)
Discontinued operations - 1,840 328
Earnings attributable to common shares $ 1,254 $ 3,764 $ 2,055
(1) Includes intercompany eliminations recorded in consolidation and certain corporate costs.
SDG&E
The decrease in earnings of $5 million (1%) in 2021 compared to 2020 was primarily due to:
▪$62 million decrease due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account, which we discuss in Note 4 of the Notes to Consolidated Financial Statements;
▪$10 million lower electric transmission margin, including the following favorable impacts in 2020 from the March 2020 FERC-approved TO5 settlement proceeding:
◦$18 million to conclude a rate base matter, and
◦$9 million from the retroactive application of the final TO5 settlement for 2019; and
▪$6 million higher income tax expense primarily from flow-through items, net of associated regulatory revenues; offset by
▪$44 million charge in 2020 for amounts to be refunded to customers and a fine related to the Energy Efficiency Program inquiry, which we discuss in Note 4 of the Notes to Consolidated Financial Statements; and
▪$31 million higher CPUC base operating margin, net of operating expenses and favorable resolution of regulatory matters in 2020.
The increase in earnings of $57 million (7%) in 2020 compared to 2019 was primarily due to:
▪$62 million increase due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account;
▪$52 million higher electric transmission margin, including an increase in authorized ROE and the following favorable impacts in 2020 from the March 2020 FERC-approved TO5 settlement:
◦$18 million to conclude a rate base matter, and
◦$9 million from the retroactive application of the final TO5 settlement for 2019;
▪$23 million higher AFUDC equity; and
▪$16 million higher income tax benefits from flow-through items; offset by
▪$44 million charge in 2020 for amounts to be refunded to customers and a fine related to the Energy Efficiency Program inquiry;
▪$31 million income tax benefit in 2019 from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed to be allocated to shareholders in a January 2019 decision;
▪$13 million higher amortization and accretion of the Wildfire Fund asset and liability, respectively; and
▪$12 million higher net interest expense.
SoCalGas
Losses of $427 million in 2021 compared to earnings of $504 million in 2020 was primarily due to:
▪$915 million increase in charges related to civil litigation and regulatory matters pertaining to the Leak comprised of $1,148 million in 2021 compared to $233 million in 2020; and
▪$64 million decrease due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account; offset by
▪$23 million higher income tax benefits from flow-through items; and
▪$21 million higher CPUC base operating margin, net of operating expenses.
The decrease in earnings of $137 million (21%) in 2020 compared to 2019 was primarily due to:
▪$233 million from impacts in 2020 related to civil litigation and regulatory matters pertaining to the Leak;
▪$38 million income tax benefit in 2019 from the impact of the January 2019 CPUC decision allocating certain excess deferred income tax balances to shareholders; and
▪$12 million higher net interest expense; offset by
▪$64 million increase due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account;
▪$29 million higher CPUC base operating margin, net of operating expenses;
▪$21 million impairment of non-utility native gas assets in 2019;
▪$10 million higher income tax benefits from flow-through items; and
▪$8 million in penalties in 2019 related to the SoCalGas billing practices OII.
Sempra Texas Utilities
The increase in earnings of $37 million (6%) in 2021 compared to 2020 was primarily due to higher equity earnings from Oncor Holdings driven by increased revenues from rate updates to reflect increases in invested capital and customer growth, offset by increased operating costs and expenses attributable to invested capital.
The increase in earnings of $51 million (10%) in 2020 compared to 2019 was primarily due to higher equity earnings from Oncor Holdings driven by:
▪increased revenues from rate updates to reflect increases in invested capital and customer growth;
▪the impact of Oncor’s acquisition of InfraREIT in May 2019; and
▪higher AFUDC equity; offset by
▪unfavorable weather and increased operating costs and expenses attributable to invested capital.
Sempra Infrastructure
Because Ecogas, our natural gas distribution utility in Mexico, uses the 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. Prior year amounts used in the variances discussed below are as adjusted for the difference in foreign currency translation rates between years. We discuss these and other foreign currency effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.”
The increase in earnings of $102 million (18%) in 2021 compared to 2020 was primarily due to:
▪$133 million higher equity earnings from Cameron LNG JV primarily due to the three-train liquefaction project achieving full commercial operations in August 2020;
▪$55 million higher earnings from asset and supply optimization primarily driven by changes in natural gas prices and higher volumes;
▪$23 million primarily due to the start of commercial operations of the Veracruz terminal in the first quarter of 2021;
▪$20 million favorable U.S. tax impact from converting SI Partners from a corporation to a partnership in October 2021;
▪$147 million earnings attributable to NCI in 2021 compared to $163 million in 2020, including a decrease of $87 million from the increase in our ownership interest in IEnova, offset by an increase of $98 million from the sale of a 20% NCI in SI Partners to KKR, which we discuss in Note 1 of the Notes to Consolidated Financial Statements; and
▪$13 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; offset by
▪$76 million higher net interest expense primarily due to:
◦$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, which we discuss in Note 7 of the Notes to Consolidated Financial Statements,
◦$19 million higher interest expense from IEnova’s issuance of senior unsecured notes in September 2020, and
◦$8 million lower net interest income from lower intercompany balances with Parent and other; and
▪$58 million unfavorable impact from foreign currency and inflation effects, net of foreign currency derivatives effects, comprised of a $47 million unfavorable impact in 2021 compared to an $11 million favorable impact in 2020.
The increase in earnings of $333 million in 2020 compared to 2019 was primarily due to:
▪$284 million higher equity earnings from Cameron LNG JV primarily due to the three-train liquefaction project achieving full commercial operations in August 2020;
▪$68 million favorable impact from foreign currency and inflation effects, net of foreign currency derivatives effects, comprised of an $11 million favorable impact in 2020 compared to a $57 million unfavorable impact in 2019;
▪$44 million higher earnings from asset and supply optimization primarily driven by changes in natural gas prices; and
▪$33 million higher earnings primarily due to the start of commercial operations of the Sur de Texas-Tuxpan marine pipeline at IMG JV in September 2019; offset by
▪$163 million earnings attributable to NCI in 2020 compared to $121 million in 2019;
▪$21 million lower earnings at the Guaymas-El Oro segment of the Sonora pipeline primarily from force majeure payments that ended in August 2019; and
▪$13 million lower earnings at TdM primarily due to scheduled major maintenance in the fourth quarter of 2020.
Sempra Renewables
As we discuss in Note 5 of the Notes to Consolidated Financial Statements, Sempra Renewables sold its remaining wind assets and investments in April 2019 upon which date the segment ceased to exist. Earnings of $59 million in 2019 included a $45 million gain on such sale.
Parent and Other
The decrease in losses of $127 million (23%) in 2021 compared to 2020 was primarily due to:
▪$50 million equity earnings in 2021 compared to $100 million equity losses in 2020 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs, which we discuss in Note 16 of the Notes to Consolidated Financial Statements;
▪$105 million lower preferred dividends as a result of $124 million lower dividends due to the mandatory conversion of all series A preferred stock and series B preferred stock in January 2021 and July 2021, respectively, offset by $19 million higher dividends due to the issuance of series C preferred stock in June 2020;
▪$59 million lower net interest expense;
▪$26 million gain on the sale of PXiSE in December 2021, which we discuss in Note 5 of the Notes to Consolidated Financial Statements; and
▪$14 million lower operating costs retained at Parent and other; offset by
▪$92 million in charges in 2021 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, which we discuss in Note 7 of the Notes to Consolidated Financial Statements;
▪$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;
▪$9 million income tax expense in 2021 compared to $26 million income tax benefit in 2020 due to changes in a valuation allowance against certain tax credit carryforwards; and
▪$31 million income tax benefit in 2020 for repatriation of foreign earnings due to extension of federal tax law.
The increase in losses of $48 million (9%) in 2020 compared to 2019 was primarily due to:
▪$100 million equity losses in 2020 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs;
▪$26 million higher preferred dividends due to the issuance of series C preferred stock in June 2020;
▪$24 million consolidated California state income tax expense in 2020 associated with income from our investments in Sempra Infrastructure entities;
▪$10 million income tax benefit in 2019 from a reduction in a valuation allowance against certain NOL carryforwards as a result of our decision to sell our South American businesses; and
▪$9 million lower net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation obligations, net of deferred compensation expenses; offset by
▪$36 million lower net interest expense;
▪$26 million income tax benefit in 2020 compared to $7 million income tax expense in 2019 from changes to a valuation allowance against certain tax credit carryforwards;
▪$11 million income tax benefit in 2020 compared to $2 million income tax expense in 2019 related to share-based compensation; and
▪$8 million decrease in losses from foreign currency derivatives used to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sale of our South American businesses.
Discontinued Operations
Discontinued operations that were previously in our Sempra South American Utilities segment include our former 100% interest in Chilquinta Energía in Chile, our former 83.6% interest in Luz del Sur in Peru and our former interests in two energy-services companies, Tecnored and Tecsur, which provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, respectively, as well as third parties. Discontinued operations also include activities, mainly income taxes related to the South American businesses, that were previously included in the holding company of the South American businesses at Parent and other.
As we discuss in Note 5 of the Notes to Consolidated Financial Statements, we completed the sales of our South American businesses in the second quarter of 2020. On April 24, 2020, we sold our equity interests in our Peruvian businesses, including our 83.6% interest in Luz del Sur and its interest in Tecsur, for cash proceeds of $3,549 million, net of transaction costs and as adjusted for post-closing adjustments, and on June 24, 2020, we sold our equity interests in our Chilean businesses, including our 100% interest in Chilquinta Energía and Tecnored and our 50% interest in Eletrans, for cash proceeds of $2,216 million, net of transaction costs and as adjusted for post-closing adjustments.
Earnings from discontinued operations of $1,840 million in 2020 included:
▪$1,499 million gain on the sale of our Peruvian businesses;
▪$248 million gain on the sale of our Chilean businesses;
▪$98 million operational earnings prior to the sale of our Peruvian and Chilean businesses; and
▪$7 million income tax benefit related to changes in outside basis differences from earnings and foreign currency effects.
The increase in earnings from our discontinued operations of $1,512 million in 2020 compared to 2019 was primarily due to:
▪$1,499 million gain on the sale of our Peruvian businesses;
▪$248 million gain on the sale of our Chilean businesses; and
▪$7 million income tax benefit in 2020 compared to $51 million income tax expense in 2019 related to changes in outside basis differences from earnings and foreign currency effects since the January 25, 2019 approval of our plan to sell our South American businesses; offset by
▪$201 million lower operational earnings mainly as a result of the sales of our Peruvian and Chilean businesses; and
▪$89 million income tax benefit in 2019 related to outside basis differences existing as of January 25, 2019.
SIGNIFICANT CHANGES IN REVENUES, COSTS AND EARNINGS
This section contains a discussion of the differences between periods in the specific line items of the Consolidated Statements of Operations for Sempra, SDG&E and SoCalGas.
Utilities Revenues and Cost of Sales
Our utilities revenues include natural gas revenues at SoCalGas and SDG&E and Sempra Infrastructure’s Ecogas and electric revenues at SDG&E. Intercompany revenues included in the separate revenues of each utility are eliminated in Sempra’s Consolidated Statements of Operations.
SoCalGas and SDG&E currently operate under a regulatory framework that permits:
▪The cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. SoCalGas’ GCIM provides SoCalGas the opportunity 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 the core customers and SoCalGas.
▪SDG&E 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.
▪SoCalGas and SDG&E to recover certain program expenditures and other costs authorized by the CPUC, or “refundable programs.”
Because changes in SoCalGas’ and SDG&E’s 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. 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 this report.
The table below summarizes utilities revenues and cost of sales.
UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
Years ended December 31,
2021 2020 2019
Natural gas revenues:
SoCalGas $ 5,515 $ 4,748 $ 4,525
SDG&E 838 694 658
Sempra Infrastructure 81 58 73
Eliminations and adjustments (101) (89) (71)
Total
6,333 5,411 5,185
Electric revenues:
SDG&E 4,666 4,619 4,267
Eliminations and adjustments (8) (5) (4)
Total
4,658 4,614 4,263
Total utilities revenues $ 10,991 $ 10,025 $ 9,448
Cost of natural gas(1):
SoCalGas $ 1,369 $ 783 $ 977
SDG&E 242 162 176
Sempra Infrastructure 24 12 14
Eliminations and adjustments (38) (32) (28)
Total
$ 1,597 $ 925 $ 1,139
Cost of electric fuel and purchased power(1):
SDG&E $ 1,069 $ 1,191 $ 1,194
Eliminations and adjustments (59) (4) (6)
Total
$ 1,010 $ 1,187 $ 1,188
(1) Excludes depreciation and amortization, which are presented separately on the Sempra, SDG&E and SoCalGas Consolidated Statements of Operations.
Natural Gas Revenues and Cost of Natural Gas
The table below summarizes the average cost of natural gas sold by Sempra California and included in cost of natural gas. The average cost of natural gas sold at each utility is impacted by market prices, as well as transportation, tariff and other charges.
SEMPRA CALIFORNIA AVERAGE COST OF NATURAL GAS
(Dollars per thousand cubic feet)
Years ended December 31,
2021 2020 2019
SoCalGas $ 4.53 $ 2.59 $ 3.07
SDG&E 5.30 3.74 3.91
In 2021 compared to 2020, our natural gas revenues increased by $922 million (17%) to $6.3 billion primarily due to:
▪$767 million increase at SoCalGas, which included:
◦$586 million increase in cost of natural gas sold, which we discuss below,
◦$129 million higher CPUC-authorized revenues,
◦$81 million higher revenues from incremental and balanced capital projects, and
◦$53 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M, offset by
◦$84 million decrease due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account, and
◦$15 million lower non-service component of net periodic benefit cost in 2021, which fully offsets in Other Income (Expense), Net;
▪$144 million increase at SDG&E, which included:
◦$80 million increase in cost of natural gas sold, which we discuss below,
◦$24 million higher CPUC-authorized revenues,
◦$20 million higher revenues primarily associated with the Pipeline Safety Enhancement Plan, and
◦$15 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M, offset by
◦$6 million decrease due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account; and
▪$23 million increase at Sempra Infrastructure primarily due to a higher residential customer rate and cost of natural gas sold.
In 2020 compared to 2019, our natural gas revenues increased by $226 million (4%) to $5.4 billion primarily due to:
▪$223 million increase at SoCalGas, which included:
◦$198 million higher CPUC-authorized revenues,
◦$144 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M, and
◦$84 million increase due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account, offset by
◦$194 million decrease in cost of natural gas sold, which we discuss below, and
◦$19 million lower non-service component of net periodic benefit cost in 2020, which fully offsets in Other Income (Expense), Net; and
▪$36 million increase at SDG&E, which included:
◦$23 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M,
◦$15 million higher CPUC-authorized revenues, and
◦$6 million increase due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account, offset by
◦$14 million decrease in cost of natural gas sold, which we discuss below; offset by
▪$15 million decrease at Sempra Infrastructure primarily due to foreign currency effects and a regulatory rate adjustment.
Our cost of natural gas increased by $672 million to $1.6 billion in 2021 compared to 2020 primarily due to:
▪$586 million increase at SoCalGas primarily from higher average natural gas prices; and
▪$80 million increase at SDG&E primarily from higher average natural gas prices.
Our cost of natural gas decreased by $214 million (19%) to $925 million in 2020 compared to 2019 primarily due to:
▪$194 million decrease at SoCalGas, including $143 million from lower average natural gas prices and $51 million from lower volumes driven primarily by weather; and
▪$14 million decrease at SDG&E, including $7 million from lower average natural gas prices and $7 million from lower volumes driven primarily by weather.
Electric Revenues and Cost of Electric Fuel and Purchased Power
In 2021 compared to 2020, our electric revenues, substantially all of which are at SDG&E, increased by $44 million (1%) to $4.7 billion primarily due to:
▪$87 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M;
▪$51 million charge in 2020 for amounts to be refunded to customers related to the Energy Efficiency Program inquiry;
▪$49 million higher CPUC-authorized revenues;
▪$41 million higher revenues associated with SDG&E’s wildfire mitigation plan;
▪$14 million higher revenues associated with a new customer information system;
▪$13 million higher revenues associated with lower income tax benefits from flow-through items; and
▪$6 million higher revenues from transmission operations, including the following favorable impacts in 2020 from the March 2020 FERC-approved TO5 settlement proceeding:
◦$26 million to settle a rate base matter, and
◦$12 million from the retroactive application of the final TO5 settlement for 2019; offset by
▪$122 million lower cost of electric fuel and purchased power, which we discuss below;
▪$77 million decrease due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account; and
▪$22 million lower revenues due to favorable resolution of regulatory matters in 2020.
In 2020 compared to 2019, our electric revenues, substantially all of which are at SDG&E, increased by $351 million (8%) to $4.6 billion primarily due to:
▪$242 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M;
▪$112 million higher revenues from transmission operations, including an increase in authorized ROE and the following favorable impacts in 2020 from the March 2020 FERC-approved TO5 settlement proceeding:
◦$26 million to settle a rate base matter, and
◦$12 million from the retroactive application of the final TO5 settlement for 2019;
▪$77 million increase due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account;
▪$35 million higher CPUC-authorized revenues; and
▪$19 million higher revenues associated with SDG&E’s wildfire mitigation plan; offset by
▪$55 million lower cost of electric fuel and purchased power, which we discuss below; and
▪$51 million charge in 2020 for amounts to be refunded to customers related to the Energy Efficiency Program inquiry.
Our utility cost of electric fuel and purchased power includes utility-owned generation and power purchased from third parties, net of sales to the California ISO. The cost of electric fuel and purchased power decreased by $177 million (15%) to $1.0 billion in 2021 compared to 2020 primarily due to:
▪$122 million at SDG&E primarily from higher sales to the California ISO due to higher market prices and lower customer demand; and
▪$55 million higher intercompany eliminations associated with sales between SDG&E and Sempra Infrastructure due to the acquisition of ESJ in March 2021.
Our utility cost of electric fuel and purchased power, substantially all of which is at SDG&E, decreased by $1 million remaining at $1.2 billion in 2020 compared to 2019 primarily due to:
▪$55 million lower recoverable cost of electric fuel and purchased power primarily due to a decrease in residential demand mainly from an increase in rooftop solar adoption; offset by
▪$52 million associated with Otay Mesa VIE, which we deconsolidated in August 2019.
Energy-Related Businesses: Revenues and Cost of Sales
The table below shows revenues and cost of sales for our energy-related businesses.
ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
Years ended December 31,
2021 2020 2019
REVENUES
Sempra Infrastructure $ 1,916 $ 1,342 $ 1,381
Sempra Renewables - - 10
Parent and other(1)
(50) 3 (10)
Total revenues $ 1,866 $ 1,345 $ 1,381
COST OF SALES(2)
Sempra Infrastructure $ 608 $ 275 $ 342
Parent and other(1)
3 1 2
Total cost of sales $ 611 $ 276 $ 344
(1) Includes eliminations of intercompany activity.
(2) Excludes depreciation and amortization, which are presented separately on Sempra’s Consolidated Statements of Operations.
In 2021 compared to 2020 revenues from our energy-related businesses, substantially all of which are at Sempra Infrastructure, increased by $521 million (39%) to $1.9 billion primarily due to:
▪$355 million increase in revenues from asset and supply optimization, contracts to sell natural gas to third parties and LNG offtake, including:
◦$309 million higher natural gas sales primarily from higher natural gas prices and volumes offset by higher unrealized losses on commodity derivatives, and
◦$46 million higher diversion revenues due to higher natural gas prices;
▪$74 million higher revenues from the Veracruz and Mexico City terminals placed in service in March and July of 2021, respectively, including a $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;
▪$63 million higher revenues from TdM mainly due to higher power prices and volumes; and
▪$41 million increase from the renewables business primarily due to the acquisition of ESJ in March 2021 and renewable assets placed in service in December 2020 and March 2021.
In 2020 compared to 2019, revenues from our energy-related businesses decreased by $36 million (3%) to $1.3 billion primarily due to:
▪$25 million lower revenues from TdM mainly due to lower volumes, offset by higher power prices;
▪$21 million lower transportation revenues primarily from force majeure payments that ended in August 2019 with respect to the Guaymas-El Oro segment of the Sonora pipeline; and
▪$18 million lower revenues from the expiration of capacity release contracts in the fourth quarter of 2019; offset by
▪$23 million increase in revenues from asset and supply optimization, contracts to sell natural gas to third parties and LNG offtake, including:
◦$44 million lower unrealized losses on commodity derivatives offset by lower natural gas sales primarily from lower natural gas prices and volumes, offset by
◦$21 million lower diversion revenues and turnback revenues due to lower natural gas prices and volumes.
The cost of sales for our energy-related businesses, substantially all of which are at Sempra Infrastructure, increased by $335 million to $611 million in 2021 compared to 2020. The increase is primarily from higher natural gas purchases related to asset and supply optimization and higher natural gas prices and volumes at TdM.
The cost of sales for our energy-related businesses, substantially all of which are at Sempra Infrastructure, decreased by $68 million (20%) to $276 million in 2020 compared to 2019. The decrease is primarily due to lower natural gas prices and volumes related to asset and supply optimization.
Operation and Maintenance
In the table below, we provide O&M by segment.
OPERATION AND MAINTENANCE
(Dollars in millions)
Years ended December 31,
2021 2020 2019
SDG&E(1)
$ 1,585 $ 1,454 $ 1,175
SoCalGas 2,180 2,029 1,780
Sempra Texas Utilities 6 - -
Sempra Infrastructure 549 427 410
Sempra Renewables - - 18
Parent and other(2)
18 30 83
Total operation and maintenance $ 4,338 $ 3,940 $ 3,466
(1) Excludes impairment losses of $2, $1, and $6 in 2021, 2020, and 2019, respectively.
(2) Includes eliminations of intercompany activity.
Our O&M increased by $398 million (10%) to $4.3 billion in 2021 compared to 2020 primarily due to:
▪$151 million increase at SoCalGas, primarily due to:
◦$98 million higher non-refundable operating costs, and
◦$53 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue;
▪$131 million increase at SDG&E, primarily due to:
◦$102 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue, and
◦$29 million higher non-refundable operating costs; and
▪$122 million increase at Sempra Infrastructure primarily due to:
◦$46 million higher expenses associated with the growth in the business and certain non-capitalized expenses at ECA LNG Phase 1 in 2021, which reached a final investment decision in November 2020,
◦$24 million from the renewables business, including the acquisition of ESJ in March 2021,
◦$17 million from the start of commercial operations of the Veracruz and Mexico City terminals in March and July of 2021, respectively, and
◦$7 million from expected credit losses on a guarantee.
Our O&M increased by $474 million (14%) to $3.9 billion in 2020 compared to 2019 primarily due to:
▪$279 million increase at SDG&E, primarily due to:
◦ $265 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue, and
◦ $18 million higher amortization in 2020 of the Wildfire Fund asset and accretion of the Wildfire Fund obligation; and
▪ $249 million increase at SoCalGas, primarily due to:
◦ $144 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue, and
◦ $105 million higher non-refundable operating costs, including labor, purchased materials and services, and administrative and support costs; offset by
▪ $53 million decrease at Parent and other primarily from lower deferred compensation expense and retained operating costs; and
▪ $18 million decrease at Sempra Renewables primarily due to lower general and administrative and other costs due to the wind-down of the business in 2019.
Aliso Canyon Litigation and Regulatory Matters
In 2021, SoCalGas recorded charges of $1,593 million compared to $307 million in 2020 related to civil litigation and regulatory matters pertaining to the Leak. We describe these charges in Note 16 of the Notes to Consolidated Financial Statements.
Impairment Losses
In 2019, SoCalGas recognized a $29 million impairment loss related to non-utility native gas assets. Also in 2019, SDG&E and SoCalGas recognized impairment losses of $6 million and $8 million, respectively, for certain disallowed capital costs in the 2019 GRC FD.
Gain (Loss) on Sale of Assets
In 2021, Parent and Other recognized a $36 million gain on the sale of PXiSE, which we discuss in Note 5 of the Notes to Consolidated Financial Statements. In 2019, Sempra Renewables recognized a $61 million gain on the sale of its remaining wind assets and investments.
Other Income (Expense), Net
As part of our central risk management function, we may enter into foreign currency derivatives to hedge SI Partners’ exposure to movements in the Mexican peso from its controlling interest in IEnova. The gains/losses associated with these derivatives are included in Other Income (Expense), Net, as described below, and partially mitigate the transactional effects of foreign currency and inflation included in Income Tax (Expense) Benefit for SI Partners’ consolidated entities and in Equity Earnings for SI Partners’ equity method investments. We also utilized foreign currency derivatives in 2020 and 2019 to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sales of our operations in Peru and Chile, respectively. We discuss policies governing our risk management below in “Part II - Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Other income, net, was $58 million in 2021 compared to other expense, net, of $48 million in 2020. The change was primarily due to:
▪$46 million lower net losses in 2021 from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions primarily due to:
◦$36 million lower losses on foreign currency derivatives and cross-currency swaps as a result of fluctuation of the Mexican peso, and
◦$19 million lower foreign currency losses on a Mexican peso-denominated loan to IMG JV, which is offset in Equity Earnings, offset by
◦$11 million lower net gains in 2021 on other foreign currency transactional effects;
▪$35 million lower non-service component of net periodic benefit cost in 2021;
▪$9 million higher investment gains in 2021 on dedicated assets in support of our executive retirement and deferred compensation plans;
▪$7 million higher AFUDC equity at SoCalGas;
▪$6 million fine at SDG&E in 2020 related to the Energy Efficiency Program inquiry; and
▪$5 million reversal of penalties in 2021 related to the SoCalGas billing practices OII; offset by
▪$8 million total decrease in regulatory interest at SDG&E and SoCalGas due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account.
Other expense, net, was $48 million in 2020 compared to other income, net, of $77 million in 2019. The change was primarily due to:
▪$92 million net losses in 2020 from interest rate and foreign exchange instruments and foreign currency transactions compared to net gains of $55 million in 2019 primarily due to:
◦$53 million losses in 2020 on foreign currency derivatives compared to $40 million gains in 2019 as a result of fluctuation of the Mexican peso, and
◦$42 million losses in 2020 compared to $30 million gains in 2019 on a Mexican peso-denominated loan to IMG JV, which is offset in Equity Earnings; offset by
◦$17 million gains in 2020 compared to $9 million losses in 2019 on other foreign currency transactional effects;
▪$20 million lower investment gains in 2020 on dedicated assets in support of our executive retirement and deferred compensation plans; and
▪$6 million fine at SDG&E in 2020 related to the Energy Efficiency Program inquiry; offset by
▪$34 million higher AFUDC equity, including $23 million at SDG&E and $7 million at SoCalGas;
▪$30 million lower non-service component of net periodic benefit cost in 2020;
▪$8 million total increase in regulatory interest at SDG&E and SoCalGas due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account; and
▪$8 million in penalties in 2019 related to the SoCalGas billing practices OII.
We provide further details of the components of other (expense) income, net, in Note 1 of the Notes to Consolidated Financial Statements.
Interest Expense
Interest expense increased by $117 million (11%) to $1.2 billion in 2021 compared to 2020 primarily due to:
▪$88 million increase 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 securities in December 2021, offset by lower long-term debt balances due to scheduled maturities in 2021; and
▪$31 million increase 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, offset by lower intercompany debt with Parent and other.
Income Taxes
The table below shows the income tax expense (benefit) and ETRs for Sempra, SDG&E and SoCalGas.
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Years ended December 31,
2021 2020 2019
Sempra:
Income tax expense from continuing operations $ 99 $ 249 $ 315
Income from continuing operations before income taxes and equity earnings $ 219 $ 1,489 $ 1,734
Equity earnings, before income tax(1)
614 294 30
Pretax income $ 833 $ 1,783 $ 1,764
Effective income tax rate 12 % 14 % 18 %
SDG&E:
Income tax expense $ 201 $ 190 $ 171
Income before income taxes $ 1,020 $ 1,014 $ 945
Effective income tax rate 20 % 19 % 18 %
SoCalGas:
Income tax (benefit) expense $ (310) $ 96 $ 120
(Loss) income before income taxes $ (736) $ 601 $ 762
Effective income tax rate 42 % 16 % 16 %
(1) We discuss how we recognize equity earnings in Note 6 of the Notes to Consolidated Financial Statements.
Sempra
Sempra’s income tax expense decreased in 2021 compared to 2020 primarily due to:
▪$445 million income tax benefit in 2021 compared to $74 million income tax benefit in 2020 associated with charges related to civil litigation and regulatory matters pertaining to the Leak; and
▪$22 million income tax benefit in 2021 from the remeasurement of certain deferred income taxes; 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;
▪$4 million income tax expense in 2021 compared to $59 million income tax benefit in 2020 from foreign currency and inflation effects and associated derivatives;
▪$9 million income tax expense in 2021 compared to $26 million income tax benefit in 2020 due to changes in valuation allowances against certain tax credit carryforwards;
▪$31 million income tax benefit in 2020 for repatriation of foreign earnings due to extension of federal tax law;
▪$10 million lower income tax benefit related to share-based compensation; and
▪lower income tax benefits from flow-through items.
Sempra’s income tax expense decreased in 2020 compared to 2019 primarily due to:
▪$59 million income tax benefit in 2020 compared to $77 million income tax expense in 2019 from foreign currency and inflation effects and associated derivatives;
▪$26 million income tax benefit in 2020 compared to $7 million income tax expense in 2019 from changes to a valuation allowance against certain tax credit carryforwards; and
▪$19 million income tax benefit in 2020 compared to $4 million income tax expense in 2019 related to share-based compensation; offset by
▪$69 million total income tax benefits in 2019 from the release of regulatory liabilities at SDG&E and SoCalGas established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision; and
▪$10 million income tax benefit in 2019 from a reduction in a valuation allowance against certain NOL carryforwards as a result of our decision to sell our South American businesses.
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 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.
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.
SDG&E
SDG&E’s income tax expense increased in 2021 compared to 2020 primarily due to lower income tax benefits in 2021 from flow-through items.
SDG&E’s income tax expense increased in 2020 compared to 2019 primarily due to:
▪higher pretax income; and
▪$31 million income tax benefit in 2019 from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision; offset by
▪higher income tax benefits in 2020 from flow-through items.
SoCalGas
SoCalGas’ income tax benefit in 2021 compared to an income tax expense in 2020 was primarily due to:
▪$445 million income tax benefit in 2021 compared to $74 million income tax benefit in 2020 associated with charges related to civil litigation and regulatory matters pertaining to the Leak; and
▪higher income tax benefits in 2021 from flow-through items.
SoCalGas’ income tax expense decreased in 2020 compared to 2019 primarily due to:
▪lower pretax income; and
▪higher income tax benefits in 2020 from flow-through items; offset by
▪$38 million income tax benefit in 2019 from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision.
Equity Earnings
Equity earnings increased by $328 million (32%) to $1.3 billion in 2021 compared to 2020 primarily due to:
▪$50 million equity earnings in 2021 compared to $100 million equity losses in 2020 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs; and
▪$136 million higher equity earnings at Sempra Infrastructure, which included:
◦$168 million higher equity earnings at Cameron LNG JV primarily due to the three-train liquefaction project achieving full commercial operations in August 2020, offset by
◦$20 million lower equity earnings at IMG JV, primarily due to foreign currency effects, including $19 million lower foreign currency gains on IMG JV’s Mexican peso-denominated loans from its JV owners, which is fully offset in Other Income (Expense), Net, and
◦$9 million lower equity earnings at TAG JV primarily due to higher income tax expense in 2021; and
▪$40 million higher equity earnings at Oncor Holdings primarily due to increased revenues from rate updates to reflect increases in invested capital and customer growth, offset by increased operating costs and expenses attributable to invested capital.
Equity earnings increased by $435 million to $1.0 billion in 2020 compared to 2019 primarily due to:
▪$487 million higher equity earnings at Sempra Infrastructure, which included:
◦$367 million higher equity earnings from Cameron LNG JV primarily due to the three-train liquefaction project achieving full commercial operations in August 2020,
◦$94 million higher equity earnings at IMG JV, primarily due to higher revenues from the start of commercial operations of the Sur de Texas-Tuxpan marine pipeline and foreign currency effects, including $42 million foreign currency gains in 2020 compared to $30 million foreign currency losses in 2019 on IMG JV’s Mexican peso-denominated loans from its JV owners, which is fully offset in Other (Expense) Income, Net, offset by lower AFUDC equity, and
◦$23 million higher equity earnings at TAG JV primarily due to lower income tax expense in 2020; and
▪$51 million higher equity earnings at Oncor Holdings primarily due to higher revenues from rate updates and customer growth, the acquisition of InfraREIT in May 2019 and higher AFUDC equity, offset by unfavorable weather and increased operating costs; offset by
▪$100 million equity losses in 2020 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs.
Earnings Attributable to Noncontrolling Interests
Earnings attributable to NCI were $145 million for 2021 compared to $172 million for 2020. The decrease of $27 million (16%) was primarily due to:
▪$87 million decrease from the increase in our ownership interest in IEnova as a result of the exchange offer and subsequent cash tender offer to acquire the publicly owned shares of IEnova; and
▪$28 million decrease mainly from foreign currency and inflation effects and associated derivatives; offset by
▪$98 million increase due to the increase in NCI as a result of the sale of a 20% NCI in SI Partners to KKR in October 2021.
Earnings attributable to NCI were $172 million for 2020 compared to $164 million for 2019. The net change of $8 million (5%) was primarily due to an increase at Sempra Infrastructure mainly from foreign currency effects as a result of fluctuation of the Mexico peso, offset by a decrease due to the sales of our Peruvian businesses in April 2020 and Chilean businesses in June 2020.
Preferred Dividends
Preferred dividends decreased by $105 million to $63 million in 2021 compared to 2020 primarily due to the conversion of all series A preferred stock and series B preferred stock in January 2021 and July 2021, respectively, offset by the issuance of series C preferred stock in June 2020.
Preferred dividends increased by $26 million (18%) to $168 million in 2020 compared to 2019 primarily due to dividends associated with our series C preferred stock, which was issued in June 2020.
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, revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra’s results of operations. Prior to the sales of our South American businesses in 2020, our operations in South America used their local currency as their functional currency.
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. Changes in foreign currency translation rates between years were negligible in 2021 compared to 2020 and resulted in $9 million lower earnings in 2020 compared to 2019.
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 (Expense), Net, for our consolidated subsidiaries and in Equity Earnings for our JVs.
We 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 (Expense), Net and Interest Expense as settlements occur.
Certain of our Mexican pipelines (namely Los Ramones I at IEnova Pipelines and Los Ramones Norte at TAG JV) 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 (LOSSES) GAINS FROM FOREIGN CURRENCY AND INFLATION EFFECTS AND ASSOCIATED DERIVATIVES
(Dollars in millions)
Total reported amounts Transactional
(losses) gains included
in reported amounts
Years ended December 31,
2021 2020 2019 2021 2020 2019
Other income (expense), net $ 58 (48) 77 $ (46) (92) 55
Income tax expense (99) (249) (315) (4) 59 (77)
Equity earnings 1,343 1,015 580 2 41 (49)
Income from continuing operations, net of income tax 1,463 2,255 1,999 (48) 8 (71)
Income from discontinued operations, net of income tax - 1,850 363 - 15 2
Earnings attributable to noncontrolling interests (145) (172) (164) 4 (24) 30
Earnings attributable to common shares 1,254 3,764 2,055 (44) (1) (39)
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 deferred income tax assets and liabilities, which are significant, 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 (Expense), 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 (Expense), 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 also utilized foreign currency derivatives in 2020 and 2019 to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sales of our operations in Peru and Chile in discontinued operations.
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
Sempra
Impact of the COVID-19 Pandemic
Our businesses that invest in, develop and operate energy infrastructure and provide electric and gas services to customers have been identified as critical or essential services in the U.S. and Mexico and have continued to operate throughout the COVID-19 pandemic. As our businesses continue to operate, our priority is the safety of our employees, customers, partners and the communities we serve. We and other companies, including our partners, are taking steps to try to protect the health and well-being of our employees and other stakeholders. We continue to work closely with local, state and federal authorities in an effort to provide essential services with minimum interruption to customers and in accordance with applicable orders, including potential vaccination mandates.
For a further discussion of risks and uncertainties related to the COVID-19 pandemic, see “Part I - Item 1A. Risk Factors.”
Liquidity
We expect to meet our cash requirements through cash flows from operations, unrestricted cash and cash equivalents, borrowings under our credit facilities, issuances of debt, distributions from our equity method investments, project financing and funding from minority interest 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 long-term debt
▪fund dividends
▪meet liquidity requirements
▪fund capital contribution requirements
▪fund expenditures related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility
▪repurchase shares of our common stock
▪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 money at reasonable rates from commercial banks, under existing revolving credit facilities or through public offerings registered with the SEC. However, our ability to access the money markets and capital markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if changing economic conditions and disruptions to the money markets and capital markets worsen. 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 financing. Also, cash flows from operations may be impacted by the timing of commencement and completion, and potentially cost overruns, of large projects and other material events, such as significant outflows resulting from the agreements expected to resolve certain material litigation related to the Leak. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) 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.
Postretirement Benefits
Sempra, SDG&E and SoCalGas have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits. The trusts’ ability to make ongoing required benefit payments have 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 other postretirement benefits 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 $236 million, $53 million and $153 million, respectively, to pension and other postretirement benefit plans in 2022 and $2.2 billion, $393 million and $1.6 billion, 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.
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 2024, SI Partners has a three-year credit agreement expiring in 2024 and IEnova has committed lines of credit that expire in 2023 and 2024. In addition, IEnova and ECA LNG Phase 1 have uncommitted revolving credit facilities that expire in 2022 and 2023.
AVAILABLE FUNDS AT DECEMBER 31, 2021
(Dollars in millions)
Sempra SDG&E SoCalGas
Unrestricted cash and cash equivalents(1)
$ 559 $ 25 $ 37
Available unused credit(2)
6,909 1,099 365
(1) Amounts at Sempra include $205 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 the 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 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. Revolving lines of credit, commercial paper and a term loan at SDG&E were our primary sources of short-term debt funding in 2021.
We discuss our short-term debt activities in Note 7 of the Notes to Consolidated Financial Statements and below in “Sources and Uses of Cash.”
The following table shows selected statistics for our commercial paper borrowings.
COMMERCIAL PAPER STATISTICS
(Dollars in millions)
Sempra SDG&E SoCalGas
December 31, December 31, December 31,
2021 2020 2019 2021 2020 2019 2021 2020 2019
Amount outstanding at period end $ 2,026 $ 113 $ 2,334 $ 401 $ - $ 80 $ 385 $ 113 $ 630
Weighted-average interest rate at period end 0.34 % 0.14 % 2.06 % 0.47 % - % 1.97 % 0.21 % 0.14 % 1.86 %
Daily weighted-average outstanding balance $ 1,107 $ 649 $ 2,246 $ 168 $ 47 $ 126 $ 118 $ 30 $ 196
Daily weighted-average yield 0.16 % 0.75 % 2.53 % 0.12 % 0.45 % 1.50 % 0.07 % 0.17 % 1.95 %
Maximum daily amount outstanding $ 2,824 $ 2,495 $ 3,243 $ 473 $ 263 $ 417 $ 580 $ 635 $ 642
Long-Term Debt Activities
Major issuances of and payments on long-term debt in 2021 included the following:
LONG-TERM DEBT ISSUANCES AND PAYMENTS
(Dollars in millions)
Issuances: Amount at issuance Maturity
Sempra 4.125% junior subordinated notes $ 1,000 2052
SDG&E 2.95% green first mortgage bonds 750 2051
Sempra Infrastructure variable rate notes 324 2025
Payments: Payments Maturity
Sempra 2.875% notes $ 500 2022
Sempra 2.9% notes 500 2023
Sempra 4.05% notes 500 2023
Sempra 3.55% notes 500 2024
Sempra 3.75% notes 350 2025
Sempra variable rate notes 850 2021
SDG&E 3% first mortgage bonds 350 2021
SDG&E 1.914% amortizing first mortgage bonds 36 2021
SDG&E variable rate 364-day term loan 200 2021
Sempra Infrastructure amortizing variable rate notes 45 2021
Sempra Infrastructure variable rate loan 183 2033
Sempra Infrastructure amortizing fixed and variable rate bank loans 396 2032
In December 2021, Sempra redeemed, at respective make-whole redemption prices, an aggregate principal amount of $2.35 billion of senior unsecured notes prior to scheduled maturities in 2022 through 2025. Upon the early redemptions, we recognized $126 million ($92 million after tax) in charges associated with the make-whole premiums and a write-off of unamortized discount and debt issuance costs.
In October 2021, Sempra Infrastructure used proceeds from borrowings against IEnova’s committed and uncommitted lines of credit to fully repay $550 million of outstanding principal plus accrued and unpaid interest on the ESJ and Ventika loans prior to their scheduled maturity dates through 2033 and recognized $54 million ($30 million after tax and NCI) in charges associated with hedge termination costs and a write-off of unamortized debt issuance costs.
As we discuss in Note 7 of the Notes to Consolidated Financial Statements, on January 11, 2022, SI Partners completed a private offering of $400 million in aggregate principal amount of 3.25% senior notes due January 15, 2032. The notes were issued at 98.903% of the principal amount and require semi-annual interest payments in January and July, commencing July 15, 2022. Sempra Infrastructure intends to use the net proceeds of $390 million for general corporate purposes, which may include the repayment of certain indebtedness of its subsidiaries.
On February 18, 2022, SDG&E entered into a $400 million, two-year term loan with a maturity date of February 18, 2024. SDG&E may request up to three borrowings for an aggregate amount of $400 million through May 18, 2022. On February 18, 2022, SDG&E borrowed $200 million. The borrowing bears interest at benchmark rates plus 62.5 bps. The margin is based on SDG&E’s long-term senior unsecured credit rating.
At December 31, 2021, Sempra expects to make interest payments on long-term debt totaling $15.7 billion, of which $793 million is expected to be paid in 2022 and $14.9 billion is expected to be paid in subsequent years through 2079. At December 31, 2021, SDG&E expects to make interest payments on long-term debt totaling $4.4 billion, of which $244 million is expected to be paid in 2022 and $4.2 billion is expected to be paid in subsequent years through 2051. At December 31, 2021, SoCalGas expects to make interest payments on long-term debt totaling $2.8 billion, of which $167 million is expected to be paid in 2022 and $2.6 billion is expected to be paid in subsequent years through 2050. We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps and cross-currency swaps. We calculate expected interest payments for variable-rate obligations based on forecasted rates in effect at December 31, 2021.
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 2021.
CREDIT RATINGS AT DECEMBER 31, 2021
Sempra SDG&E SoCalGas
Moody’s Baa2 with a stable outlook A3 with a stable outlook A2 with a stable outlook
S&P BBB+ with a negative outlook BBB+ with a stable outlook A with a negative outlook
Fitch BBB+ with a stable outlook BBB+ with a stable outlook A with a stable outlook
A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in 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 three major 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, 2021.
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, 2021, Sempra had $637 million in loans due from unconsolidated affiliates and $287 million in loans due to unconsolidated affiliates.
Note Receivable
As we discuss in Note 1 of the Notes to Consolidated Financial Statements, in November 2021, Sempra loaned $300 million to KKR in exchange for an interest-bearing promissory note and reimbursed $5 million of loan-related transaction costs incurred by KKR. The promissory note is due to be repaid in full no later than October 1, 2029 and bears compound interest at 5% per annum.
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 the California legislature, litigation and the changing energy marketplace, as well as other matters described in this report. SDG&E and SoCalGas expect that the available unused credit from their credit facilities described above, cash flows from operations, and debt issuances will continue to be adequate to fund their respective current operations and planned capital expenditures. Additionally, as we discuss below, Sempra elected to make an equity contribution to SoCalGas in 2021 and may elect to make additional equity contributions in the future that are intended to maintain SoCalGas’ approved capital structure in connection with the accruals related to the Leak. We describe SDG&E’s and SoCalGas’ commitments related to construction projects, operating and finance leases, and purchase obligations related to the procurement of power and natural gas in Note 16 of the Notes to Consolidated Financial Statements. SDG&E and SoCalGas manage their capital structures and pay dividends when appropriate and as approved by their respective boards of directors.
As we discuss in Note 4 of the Notes to Consolidated Financial Statements, changes in 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.
COVID-19 Pandemic Protections
SDG&E and SoCalGas are continuing to monitor the impacts of the COVID-19 pandemic on cash flows and results of operations. Some customers have experienced and continue to experience a diminished ability to pay their electric or gas bills, leading to slower payments and higher levels of nonpayment than has been the case historically. These impacts could become significant and could require modifications to our financing plans.
In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E and SoCalGas implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers (except for SoCalGas’ noncore customers), waiving late payment fees, and offering flexible payment plans. At the CPUC’s direction, SDG&E and SoCalGas are automatically enrolling residential and small business customers with past-due balances in long-term repayment plans.
In 2021, SDG&E and SoCalGas applied, on behalf of their customers, for financial assistance from the California Department of Community Services and Development under the California Arrearage Payment Program, which provided funds of $63 million and $79 million for SDG&E and SoCalGas, respectively. In the first quarter of 2022, SDG&E and SoCalGas received and will apply the amounts directly to eligible customer accounts to reduce past due balances.
SDG&E and SoCalGas have been authorized to track and request recovery of incremental costs associated with complying with customer protection measures implemented by the CPUC related to the COVID-19 pandemic, including costs associated with suspending service disconnections and uncollectible expenses that arise from customers’ failure to pay. SDG&E and SoCalGas expect to pursue recovery of small and medium-large commercial and industrial customers’ tracked costs in rates in future CPUC proceedings, which recovery is not assured. Uncollectible expenses related to residential customers are recorded in a two-way balancing account as we discuss below.
The continuation of these circumstances could result in a further reduction in payments received from SDG&E’s and SoCalGas’ customers and a further increase in uncollectible accounts, which could become material, and any inability or delay in recovering all or a substantial portion of these costs could have a material adverse effect on the results of operations, financial condition, cash flows and/or prospects of Sempra, SDG&E and SoCalGas. We discuss regulatory mechanisms in Note 4 of the Notes to Consolidated Financial Statements.
Disconnection OIR
In June 2020, the CPUC issued a decision addressing residential service disconnections that, among other things, allows SDG&E and SoCalGas to each establish a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills. This decision, which became effective in February 2021, also directs SDG&E and SoCalGas to each establish an AMP that provides successfully participating, income-qualified residential customers with relief from outstanding utility bill amounts. SDG&E and SoCalGas have recorded changes in their allowances for uncollectible accounts at December 31, 2021 primarily related to expected forgiveness of outstanding bill amounts for customers eligible under the AMP. The AMP could result in a further reduction in payments received from SDG&E’s and SoCalGas’ customers and a further increase to uncollectible accounts, which could become material, and any inability to recover these costs could have a material adverse effect on the results of operations, financial condition, cash flows and/or prospects of Sempra, SDG&E and SoCalGas.
CCM
A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized return on rate base. In December 2019, the CPUC approved the cost of capital and rate structures for SDG&E and SoCalGas that became effective on January 1, 2020 and will remain in effect through December 31, 2022, subject to the CCM.
The CCM 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 CCM benchmark rate is the basis of comparison to determine if the CCM is triggered, 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 index applicable to SDG&E and SoCalGas is based on each utility’s credit rating. SDG&E’s CCM benchmark rate is 4.498% based on Moody’s Baa- utility bond index, and SoCalGas’ CCM benchmark rate is 4.029% based on Moody’s A- utility bond index. Alternatively, under the CCM, SDG&E and SoCalGas are permitted to file a cost of capital application 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.
For the measurement period ended September 30, 2021, the CCM would trigger for SDG&E because the average Moody’s Baa- utility bond index between October 1, 2020 and September 30, 2021 was 1.17% below SDG&E’s CCM benchmark rate of 4.498%. In August 2021, SDG&E filed an application with the CPUC to update its cost of capital effective January 1, 2022 due to the ongoing effects of the COVID-19 pandemic rather than have the CCM apply. In this application, SDG&E proposed to adjust its authorized capital structure by increasing its common equity ratio from 52% to 54%. SDG&E also proposed to increase its authorized ROE from 10.20% to 10.55% and decrease its authorized cost of debt from 4.59% to 3.84%. As a result, SDG&E’s proposed return on rate base would decrease from 7.55% to 7.46% if such application is approved by the CPUC as filed. SDG&E filed a joint motion with PG&E and Edison to consolidate all three utilities’ cost of capital applications given the overlapping issues of law and fact, which joint motion was granted in October 2021. In December 2021, the CPUC established a proceeding to determine if SDG&E’s cost of capital was impacted by an extraordinary event. If the CPUC finds that there was not an extraordinary event, the CCM would be effective retroactive to January 1, 2022 and would automatically adjust SDG&E’s authorized ROE from 10.20% to 9.62% and adjust its authorized cost of debt to reflect the then current embedded cost and projected interest rate. If the CPUC finds that there was an extraordinary event, it will then determine whether to suspend the CCM for 2022 and preserve SDG&E’s current authorized cost of capital or hold a second phase of the proceeding to set a new cost of capital for 2022. SDG&E expects a final decision in the second half of 2022. In December 2021, the CPUC granted SDG&E the establishment of memorandum accounts effective January 1, 2022 to track any differences in revenue requirement resulting from the interim cost of capital decision expected in 2022.
For the measurement period ended September 30, 2021, the CCM was not triggered for SoCalGas. SDG&E and SoCalGas are required to file their next cost of capital applications in April 2022 for a January 1, 2023 effective date. We further discuss the CCM in “Part I - Item 1A. Risk Factors.”
SDG&E
Wildfire Fund
The carrying value of SDG&E’s Wildfire Fund asset totals $360 million at December 31, 2021. We describe the Wildfire Legislation, related accounting treatment 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 an impairment charge against earnings when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. PG&E has 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 Cost Recovery Mechanism
In July 2021, SDG&E filed a request with the CPUC to establish an interim cost recovery mechanism that would recover in rates 50% of its wildfire mitigation plan regulatory account balance as of January 1 of each year. Such potential recovery would be incremental to wildfire costs authorized in its GRC and would be subject to reasonableness review. We expect the CPUC to issue a final decision in the first half of 2022.
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 have 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
SoCalGas’ future performance and liquidity will be impacted by the resolution of legal, regulatory and other matters concerning the Leak, which we discuss below, in Note 16 of the Notes to Consolidated Financial Statements, and in “Part I - Item 1A. Risk Factors.”
Aliso Canyon Natural Gas Storage Facility Gas Leak
From October 23, 2015 through February 11, 2016, SoCalGas experienced a natural gas leak from one of the injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility located in Los Angeles County.
Cost Estimate, Accounting Impact and Insurance. At December 31, 2021, SoCalGas estimates certain costs related to the Leak are $3,221 million (the cost estimate). This cost estimate may increase significantly as more information becomes available. A portion of the cost estimate has been paid, and $1,983 million is accrued as Reserve for Aliso Canyon Costs at December 31, 2021 on SoCalGas’ and Sempra’s Consolidated Balance Sheets. Sempra elected to make an $800 million equity contribution to SoCalGas in September 2021 and may elect to make additional equity contributions in the future that are intended to maintain SoCalGas’ approved capital structure in connection with the accruals related to these agreements. Sempra does not expect to issue common equity to fund any such equity contributions.
Except for the amounts paid or estimated to settle certain legal and regulatory matters, the cost estimate does not include (i) any amounts necessary to resolve claims of Individual Plaintiffs who do not agree to participate in the settlement of the Individual Actions or members of the Property Class Action who opt out of that settlement or (ii) the matters that we describe in “Civil Litigation - Unresolved Litigation” and “Regulatory Proceedings” in Note 16 of the Notes to Consolidated Financial Statements to the extent it is not possible to predict at this time the outcome of these actions or reasonably estimate the possible costs or a range of possible costs for damages, restitution, civil or administrative fines or penalties, defense, settlement or other costs or remedies that may be imposed or incurred. The cost estimate also does not include certain other costs incurred by Sempra
associated with defending against shareholder derivative lawsuits and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Further, we are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued. These costs or losses not included in the cost estimate 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.
We have received insurance payments for many of the categories of costs included in the cost estimate, including temporary relocation and associated processing costs, control-of-well expenses, costs of the government-ordered response to the Leak, certain legal costs and lost gas. As of December 31, 2021, we recorded the expected recovery of the cost estimate related to the Leak of $360 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra’s Consolidated Balance Sheets. This amount is exclusive of insurance retentions and $919 million of insurance proceeds we received through December 31, 2021. We intend to pursue the full extent of our insurance coverage for the costs we have incurred. Other than insurance for certain future defense costs we may incur as well as directors’ and officers’ liability, we have exhausted all of our insurance in this matter. We continue to pursue other sources of insurance coverage for costs related to this matter, but we may not be successful in obtaining additional insurance recovery for any of these costs. If we are not able to secure additional insurance recovery, if any costs we have recorded as an insurance receivable are not collected, if there are delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes while the associated costs are not tax deductible, such amounts, which could be significant, 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 for service reliability during peak demand periods, including peak electric generation needs in the summer and consumer heating needs in the winter. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important component of SoCalGas’ delivery system. As a result of the Leak, the CPUC has issued a series of directives to SoCalGas specifying the range of working gas to be maintained in the Aliso Canyon natural gas storage facility as well as protocols for the withdrawal of gas, to support safe and reliable natural gas service. In February 2017, the CPUC opened a proceeding pursuant to the 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 considering alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated.
At December 31, 2021, the Aliso Canyon natural gas storage facility had a net book value of $883 million. 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, incur higher than expected operating costs and/or be required to make 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.
Labor Relations
Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council. On October 1, 2021, a new collective bargaining agreement for these employees, covering wages, hours, working conditions, and medical and other benefits, went into effect through September 2024.
Franchise Agreement
SoCalGas’ natural gas franchise agreement with the City of Los Angeles expired on December 31, 2021. In December 2021, the Los Angeles City Council awarded SoCalGas a new, 21-year natural gas franchise following an invitation for bids, which was approved and signed by the City of Los Angeles mayor in January 2022. The 21-year term consists of an initial 13-year term from the effective date, followed by an 8-year term that the City of Los Angeles has the option to terminate. Among other conditions, the new franchise agreement is subject to CPUC approval of the rates and surcharges therein for it to become effective, which SoCalGas filed for in February 2022. In the interim, SoCalGas continues to serve customers located in the City of Los Angeles in accordance with the expired agreement by operation of law.
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 or is unable to access sufficient capital 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 pay dividends 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 pay dividends 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.
Winter Weather Event
In February 2021, ERCOT required electric distribution companies, including Oncor, to significantly reduce demand on the grid because electricity generation was insufficient to meet demand due to extreme winter weather. As a result of the load shedding events and state-wide power outages, the PUCT, other governmental authorities or third parties, including Oncor’s customers, have taken or could take other measures to address financial challenges experienced as a result of the event, which could adversely impact Oncor’s collections and cash flows and, in turn, could adversely impact Sempra. The Texas Legislature has passed, and the Governor of Texas has signed, various legislation affecting the ERCOT market, which addresses matters including certain weatherization requirements and fines of up to $1 million per day for failures to comply with such requirements, enabling ERCOT to finance certain amounts owed by ERCOT market participants relating to the winter weather event, creation of the Texas Energy Reliability Council, identification of gas facilities that are critical to electric-generator fuel supplies, coordination between the gas and electric industries, and changes in the composition of the PUCT and the ERCOT board of directors. In addition, various regulatory and governmental entities have also commenced investigations or indicated an intent to investigate the operation of the ERCOT grid during this extreme winter weather event and potential future actions to improve grid reliability. Any significant changes relating to the ERCOT market that impact transmission and distribution utilities as a result of such proceedings or otherwise could materially adversely impact Oncor. If Oncor does not successfully respond to these changes and any other legislative, regulatory, or market or industry developments applicable to it, Oncor could suffer a deterioration in its results of operations, financial condition, cash flows and/or prospects, which could materially adversely affect Sempra’s results of operations, financial condition, cash flows and/or prospects.
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 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 minority interest owners, bank financing, issuances of debt, project financing and partnering in JVs. We describe Sempra Infrastructure’s commitments related to construction and development projects in Note 16 of the Notes to Consolidated Financial Statements.
As we discuss in Note 1 of the Notes to Consolidated Financial Statements, in October 2021, Sempra Infrastructure completed the sale of a 20% NCI in SI Partners to KKR for cash proceeds of $3.2 billion, including post-closing adjustments and net of $173 million in transaction costs. We used the proceeds from the sale to KKR to partially fund the early redemption of $2.35 billion of Sempra’s long-term debt, which we discuss above in “Long-Term Debt Activities,” and to help fund capital investments in support of incremental growth at Sempra California and Sempra Texas Utilities.
In December 2021, we entered into an agreement to sell a 10% NCI in SI Partners to ADIA for cash proceeds of $1.8 billion, subject to adjustments. We expect the transaction will close in the summer of 2022. We intend to use the expected proceeds from the sale to ADIA to help fund incremental capital expenditures at Sempra California and Sempra Texas Utilities, to repay commercial paper borrowings used to repurchase $500 million in shares of our common stock ($300 million of which was completed in the fourth quarter of 2021 and an additional $200 million of which was completed in the first quarter of 2022), and further strengthen our balance sheet. Our ability to complete the ADIA transaction is subject to a number of risks, including, among others, the ability to obtain regulatory and third-party approvals and satisfy other customary closing conditions. If we are not able to obtain these approvals and satisfy all other closing conditions in a timely manner or on satisfactory terms, then the
proposed transaction may be abandoned and/or our prospects for Sempra Infrastructure and, in turn, Sempra’s results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
Following the closing of the ADIA transaction, Sempra, KKR and ADIA would directly or indirectly own a 70%, 20%, and 10%, interest, respectively, in SI Partners. The sale of NCI in SI Partners to KKR has reduced and the agreed sale of NCI in SI Partners to ADIA would further reduce our ownership interest in SI Partners, and these sales require us to share control over certain business decisions with the minority partners, which introduces a number of risks associated with sharing business control. Moreover, the decrease in our ownership of SI Partners also decreases our share of the cash flows, profits and other benefits these businesses currently or may in the future produce, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
LNG and Net-Zero Solutions
Cameron LNG JV Liquefaction Expansion Project (Phase 2). Cameron LNG JV received major permits and FTA and non-FTA approvals associated with the expansion of the current configuration of the Cameron LNG JV liquefaction project beyond Phase 1. Those permits for the Phase 2 project included up to two additional liquefaction trains and up to two additional full containment LNG storage tanks. In January 2022, Cameron LNG JV filed an amendment, subject to approval by the FERC, to modify the permits to allow the use of electric drives, instead of gas turbine drives, which would reduce overall emissions. We expect the proposed expansion project will initially have one train with offtake capacity of approximately 6.75 Mtpa, with the ability to increase capacity with debottlenecking of the existing trains, and the site can accommodate additional trains beyond Phase 2.
Sempra has entered into MOUs with TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation that provide a framework for cooperation for the development of and offtake from the potential Cameron LNG JV Phase 2 project. The ultimate participation of and offtake by TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation remains subject to negotiation and finalization of definitive agreements, among other factors, and TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation have no commitment to participate in, or enter into offtake agreements with respect to, the Phase 2 project unless such definitive agreements are established.
Expansion of the Cameron LNG JV liquefaction facility beyond the first three trains is subject to certain restrictions and conditions under the JV project financing agreements, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from the Phase 1 project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the partners, including with respect to the equity investment obligation of each partner. Discussions among all the Cameron LNG JV partners have been taking place regarding how an expansion may be structured, including a facility design utilizing electric drives, and we expect that discussions will continue. Although we are working towards making a final investment decision in the first half of 2023, the timing of when or if Cameron LNG JV will receive approval to amend the permits is uncertain, and there is no assurance that the Cameron LNG JV members will unanimously agree in a timely manner or at all on an expansion structure, which, if not accomplished, would materially and adversely impact the development of the Phase 2 project.
The development of the potential Cameron LNG JV Phase 2 project is subject to numerous other risks and uncertainties, including securing binding customer commitments; reaching unanimous agreement with our partners to proceed; obtaining and maintaining a number of permits and regulatory approvals; securing financing; negotiating and completing suitable commercial agreements, including a definitive EPC contract, equity acquisition and governance agreements; reaching a positive final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Part I - Item 1A. Risk Factors.”
ECA LNG Liquefaction Export Projects. Sempra Infrastructure is developing two natural gas liquefaction export projects at its existing ECA Regas Facility. The liquefaction export projects, which are planned for development in two phases (a mid-scale project by ECA LNG Phase 1 that is under construction and a proposed large-scale project by ECA LNG Phase 2), are being developed to provide buyers with direct access to North American west coast LNG supplies. We do not expect the construction or operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility, but have planned measures to limit disruption of operations should any arise. However, 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, making the decisions on whether and how to pursue the 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.
In March 2019, ECA LNG received two authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from its ECA LNG Phase 1 project, which is a one-train natural gas liquefaction facility with a
nameplate capacity of 3.25 Mtpa and initial offtake capacity of approximately 2.5 Mtpa that is under construction, and its proposed ECA LNG Phase 2 project that is in development.
In April 2020, ECA LNG Phase 1 executed definitive 20-year LNG sale and purchase agreements with Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG and with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG. In December 2020, an affiliate of TotalEnergies SE acquired a 16.6% ownership interest in ECA LNG Phase 1, with Sempra Infrastructure retaining an 83.4% ownership interest. Our MOU with Mitsui & Co., Ltd. provides a framework for Mitsui & Co., Ltd.’s potential offtake of LNG from, and potential acquisition of an equity interest in, ECA LNG Phase 2.
In February 2020, we entered into an EPC contract with Technip Energies for the engineering, procurement and construction of the ECA LNG Phase 1 project. Since reaching a positive final investment decision with respect to the project in November 2020, we released Technip Energies to commence work to construct the ECA LNG Phase 1 project. The total price of the EPC contract is estimated at approximately $1.5 billion. We estimate that capital expenditures will approximate $2.0 billion, including capitalized interest and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ, perhaps substantially, from our estimates. We expect ECA LNG Phase 1 to begin producing LNG by the end of 2024.
In December 2020, ECA LNG Phase 1 entered into a five-year loan agreement for an aggregate principal amount of up to $1.6 billion, of which $341 million was outstanding at December 31, 2021. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project. We discuss the details of this loan in Note 7 of the Notes to Consolidated Financial Statements.
The construction of the ECA LNG Phase 1 project and the development of the potential ECA LNG Phase 2 project are subject to numerous risks and uncertainties. For Phase 1, these include maintaining permits and regulatory approvals; construction delays; securing and maintaining commercial arrangements, such as gas supply and transportation agreements; the impact of recent and proposed changes to the law in Mexico; and other factors associated with the project and its construction. For Phase 2, these include obtaining binding customer commitments; the receipt of a number of permits and regulatory approvals; obtaining financing; negotiating and completing suitable commercial agreements, including a definitive EPC contract, equity acquisition and governance agreements, LNG sales agreements and gas supply and transportation agreements; reaching a positive final investment decision; the impact of recent and proposed changes to the law in Mexico; and other factors associated with this potential investment. In addition, as we discuss in Note 16 of the Notes to Consolidated Financial Statements, an unfavorable decision on certain property disputes or permit challenges, an unfavorable judgment that does not allow Sempra Infrastructure to secure new or renew existing LDA authorizations, or an extended dispute with existing customers at the ECA Regas Facility, could materially adversely affect the development and construction of these projects and Sempra’s results of operations, financial condition, cash flows and/or prospects, including the impairment of all or a substantial portion of the capital costs invested in the projects to date. For a discussion of these risks, see “Part I - Item 1A. Risk Factors.”
Port Arthur LNG Liquefaction Export Project. Sempra Infrastructure is developing a proposed natural gas liquefaction export project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. Sempra Infrastructure received authorizations from the DOE in August 2015 and May 2019 that collectively permit the LNG to be produced from the proposed Port Arthur LNG project to be exported to all current and future FTA and non-FTA countries. In February 2020, Sempra Infrastructure filed an application with the DOE to permit LNG produced from a second phase of the proposed Port Arthur LNG facility 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 proposed Port Arthur LNG liquefaction facility, along with certain natural gas pipelines, including the Louisiana Connector and Texas Connector Pipelines, that could be used to supply feed gas to the liquefaction facility if and when the project is completed. In February 2020, Sempra Infrastructure filed a FERC application for the siting, construction and operation of a second phase of the proposed Port Arthur LNG facility, including the potential addition of two liquefaction trains.
In February 2020, we entered into an EPC contract with Bechtel for the proposed Port Arthur LNG liquefaction project. The EPC contract contemplates the construction of two liquefaction trains with a nameplate capacity of approximately 13.5 Mtpa, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services. In December 2020, we amended and restated the EPC contract to reflect an estimated price of approximately $8.7 billion. Since we did not issue a full notice to proceed by July 15, 2021, agreement by both parties on an amendment to the EPC contract is necessary to proceed. Such amendment may adjust the EPC contract price and the EPC schedule and could potentially include other changes to the work and terms and conditions of the EPC contract. Any agreement on such an amendment by both parties or on favorable terms to Sempra cannot be assured.
In December 2018, Polish Oil & Gas Company (PGNiG) and Port Arthur LNG entered into a definitive 20-year agreement for the sale and purchase of 2 Mtpa of LNG per year from the Port Arthur LNG liquefaction export project. In July 2021, the agreement was terminated and PGNiG and Sempra Infrastructure entered into an MOU to cooperate on the transition of the 2 Mtpa to Sempra Infrastructure’s portfolio of other projects.
In May 2019, Aramco Services Company and Sempra Infrastructure signed a Heads of Agreement for the negotiation of a definitive 20-year LNG sale and purchase agreement for 5 Mtpa of LNG offtake from the Port Arthur LNG liquefaction export project. The Heads of Agreement also included the negotiation of a potential 25% equity investment in the project. In January 2020, Aramco Services Company and Sempra Infrastructure signed an Interim Project Participation Agreement related to the proposed project. In June 2021, Aramco Services Company and Sempra Infrastructure agreed to allow the Heads of Agreement and Interim Project Participation Agreement to expire.
We continue work to progress development of the proposed Port Arthur LNG liquefaction export project and are evaluating design changes that could reduce overall emissions, including electric drives, renewable power sourcing and other technological solutions. Given uncertainties in the energy markets, including real-time developments of new technologies that could impact the design, scale and structure of the project, we continue to evaluate the timing of a final investment decision.
Development of the Port Arthur LNG liquefaction export project is subject to a number of risks and uncertainties, including obtaining customer commitments; identifying suitable project partners; completing the required commercial agreements, such as equity acquisition and governance agreements, LNG sales agreements and gas supply and transportation agreements; completing construction contracts, including an amendment to the EPC contract with Bechtel; securing and maintaining all necessary permits and approvals; obtaining financing and incentives; reaching a positive final investment decision; and other factors associated with the potential investment. An unfavorable outcome with respect to any of these factors could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects, including the impairment of all or a substantial portion of the capital costs invested in the project to date. For a discussion of these risks, see “Part I - Item 1A. Risk Factors.”
Vista Pacifico LNG Liquefaction Export Project. Sempra Infrastructure is developing Vista Pacifico LNG, a potential natural gas liquefaction, storage, and mid-scale export facility proposed to be located in the vicinity of Topolobampo in Sinaloa, Mexico, under an MOU with the CFE that contemplates the negotiation of definitive agreements that would cover development of Vista Pacifico LNG, as well as a separate natural gas regasification project in La Paz Baja California Sur, and the potential re-routing of a portion of the Guaymas-El Oro segment of the Sonora pipeline and resumption of its operations through mutual agreements between the CFE and the Yaqui tribe. The proposed LNG 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. In November 2020, Sempra Infrastructure filed an application with the DOE to permit the export of 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 and non-FTA countries. In April 2021, the DOE granted Vista Pacifico’s LNG export authorization application for FTA countries.
The development of the potential Vista Pacifico LNG project (as well as the other projects discussed above) is subject to numerous risks and uncertainties, including securing binding customer commitments; obtaining and maintaining a number of permits and regulatory approvals; securing financing; identifying suitable project partners; negotiating and completing suitable commercial agreements, including a definitive EPC contract, equity acquisition and governance agreements, LNG sales agreements and gas supply and transportation agreements; reaching a positive final investment decision; the impact of recent and proposed changes to the law in Mexico; and other factors associated with this potential investment. For a discussion of these risks, see “Part I - Item 1A. Risk Factors.”
Hackberry Carbon Sequestration Project. Sempra Infrastructure is developing the potential Hackberry carbon capture and sequestration project in Hackberry, Louisiana. This proposed project in development is a carbon dioxide storage facility with the intended capability of permanently sequestering carbon dioxide from Cameron LNG JV. In the third quarter of 2021, Sempra Infrastructure filed an application with the EPA for a Class VI carbon injection well to advance this project.
The development of the potential Hackberry carbon capture and sequestration project is subject to numerous risks and uncertainties, including securing binding customer commitments; identifying suitable project partners; obtaining and maintaining a number of permits and regulatory approvals; securing financing; negotiating and completing suitable commercial agreements, including a definitive EPC contract, and equity acquisition and governance agreements; reaching a positive final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Part I - Item 1A. Risk Factors.”
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 9 of the Notes to Consolidated Financial Statements.
Energy Networks
Construction Projects. Sempra Infrastructure began commercial operations of its new terminals for the receipt, storage and delivery of refined fuel products in the new port of Veracruz on March 19, 2021 and in Mexico City on July 2, 2021. The two terminals have a combined storage capacity of more than 2.7 million barrels. The storage capacity for both terminals is contracted with Valero Energy Corporation.
Sempra Infrastructure is currently constructing additional terminals for the receipt, storage, and delivery of liquid fuels in the vicinity of Puebla and Topolobampo. As part of an industrywide audit and investigative process initiated by the CRE to enforce fuel procurement laws, federal prosecutors conducted inspections at several refined products terminals, including Sempra Infrastructure’s refined products terminal in Puebla, to confirm that the gasoline and/or diesel in storage were legally imported. During the inspection of the Puebla terminal in September 2021, a federal prosecutor took samples from all the train and storage tanks in the terminal and ordered that the facility be temporarily shut down during the pendency of the analysis of the samples and investigation, while leaving the terminal in Sempra Infrastructure’s custody. In addition, in November 2021, the CRE notified Sempra Infrastructure of the commencement of an administrative proceeding for revoking the storage permit at the Puebla terminal due to alleged breach of its terms and conditions. Although Sempra Infrastructure filed an amparo lawsuit against the closure and has submitted proof of the legal origin of the products to the prosecutor’s office, we are unable to predict when the investigation will be completed, the outcome of the administrative proceeding or whether the facility will be able to commence commercial operations. If the terminal were to be shut down, storage permits were to be revoked or commissioning operations significantly curtailed for an extended period of time, Sempra’s results of operations, financial condition, cash flows and/or prospects could be materially adversely affected. We expect the Topolobampo project to commence commercial operations in the first half of 2022. The ability to successfully complete major construction projects is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I - Item 1A. Risk Factors.”
Sempra Infrastructure is also developing terminals for the receipt, storage, and delivery of liquid fuels in the vicinity of Manzanillo and Ensenada.
Expected commencement dates could be delayed by worsening or extended disruptions of project construction caused by the COVID-19 pandemic or other factors outside our control. Sempra Infrastructure is continuing to monitor the impacts of the COVID-19 pandemic on cash flows and results of operations.
Clean Power
Construction Projects. Sempra Infrastructure completed construction and began commercial operations of a new 150-MW solar power generation facility (Border Solar) in Ciudad Juárez, Chihuahua on March 25, 2021. Border Solar is fully contracted by third-party companies under long-term PPAs expiring in 2032 and 2037, though it requires an amendment to its self-supply permit granted by the CRE in order to supply its customers. The energy production is currently being sold in the open market at variable rates.
ESJ completed construction and began commercial operations of a second, 108-MW wind power generation facility on January 15, 2022. This second wind power generation facility is fully contracted by SDG&E under a long-term PPA expiring in 2042.
Acquisition of ESJ. As we discuss in Note 5 of the Notes to Consolidated Financial Statements, in March 2021, Sempra Infrastructure increased its ownership interest in ESJ from 50% to 100% by acquiring Saavi Energía’s 50% equity interest in ESJ.
Legal and Regulatory Matters
See Note 16 of the Notes to Consolidated Financial Statements for discussions of the following legal and regulatory matters affecting our operations in Mexico:
Energía Costa Azul
▪Land Disputes
▪Environmental and Social Impact Permits
▪Customer Dispute
One or more unfavorable final decisions on these land and customer 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.
Sonora Pipeline
▪Guaymas-El Oro Segment
▪Sasabe-Puerto Libertad-Guaymas Segment
Our investment in the Guaymas-El Oro segment of the Sonora pipeline could be subject to impairment if Sempra Infrastructure is unable to make certain repairs (which have not commenced) or re-route a portion of the pipeline (which has not been agreed to by the parties, but is subject to negotiation pursuant to a non-binding MOU, as described above) and resume operations in the Guaymas-El Oro segment of the Sonora pipeline or if Sempra Infrastructure terminates the contract and is unable to obtain recovery. In addition, the failure to stay the court judgment nullifying Sempra Infrastructure’s right-of-way easement for a portion of the Sasabe-Puerto Libertad-Guaymas segment of the Sonora pipeline pending the resolution of Sempra Infrastructure’s planned special judicial action or prevail in preserving the easement in the special judicial action could require us to modify the route of the pipeline and could require a temporary shutdown of this portion of the pipeline. Any such occurrence could 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
▪Transmission Rates for Legacy Generation Facilities
▪Offtakers of Legacy Generation Permits
▪Amendments to Mexico’s Electricity Industry Law
▪Amendments to Mexico’s Hydrocarbons Law
▪Amendments to Mexico’s General Foreign Trade Rules
▪Proposed Constitutional Reform in Mexico
Sempra Infrastructure and other parties affected by these resolutions, orders, decrees, regulations and proposed amendments to Mexican law have challenged them by filing amparo and other claims, some of which have been granted injunctive relief. The court-ordered injunctions or suspensions provide temporary relief until Mexico’s federal district court or Supreme Court ultimately resolves the amparo and other claims. If passed in its current form, the proposed constitutional reform introduces significant changes to the legal and economic principles underlying the country’s energy reform of 2013, generating imminent risks for private investments in this sector. An unfavorable decision on one or more of these amparo or other challenges, the potential for extended disputes, or if passed in its current form, the proposed constitutional reform 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, 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 our business, results of operations, financial condition, cash flows and/or prospects.
Parent and Other
PXiSE
In December 2021, Parent and other completed the sale of its 80% interest in PXiSE for total cash proceeds of $38 million, net of transaction costs totaling $4 million, and recorded a $36 million ($26 million after tax) gain, which is included in Gain (Loss) on Sale of Assets on Sempra’s Consolidated Statement of Operations.
SOURCES AND USES OF CASH
The following tables include only significant changes in cash flow activities for each of our registrants.
CASH FLOWS FROM OPERATING ACTIVITIES
(Dollars in millions)
Years ended December 31, Sempra SDG&E SoCalGas
2021 $ 3,842 $ 1,376 $ 1,033
2020 2,591 1,389 1,526
Change $ 1,251 $ (13) $ (493)
Net increase in Reserve for Aliso Canyon Costs, current and noncurrent, due to $1,083 higher accruals and $14 lower payments $ 1,097 $ 1,097
Higher distributions received from Cameron LNG JV 258
Net decrease in Insurance Receivable for Aliso Canyon primarily due to $193 lower accruals and $2 lower insurance proceeds 191 191
Change in accounts payable 189 $ (24) 117
Release of a regulatory liability in 2020 related to 2016-2018 income tax expense forecasting differences 175 86 89
Change in bad debt regulatory assets 101 63 38
Change in income taxes receivable/payable, net 56 (149) (232)
Change in net undercollected regulatory balancing accounts (including long-term amounts in regulatory assets) (182) (174) (8)
Increase in purchases of GHG allowances (229) (31) (197)
Change in net margin posted at Sempra Infrastructure (266)
Change in accounts receivable (271) 29 (282)
(Lower) higher net income (loss), adjusted for noncash items included in earnings (979) 160 (1,291)
Other 60 27 (15)
Change in net cash flows from discontinued operations primarily due to $1,161 income taxes paid related to the sale of our South American businesses 1,051
$ 1,251 $ (13) $ (493)
2020 $ 2,591 $ 1,389 $ 1,526
2019 3,088 1,090 868
Change $ (497) $ 299 $ 658
Change in intercompany activities with discontinued operations (including $403 dividends received from our South American businesses in 2019) $ (378)
Net increase in Insurance Receivable for Aliso Canyon primarily due to $132 higher accruals and $94 lower insurance proceeds received (228) $ (228)
Change in accounts receivable (224) $ (119) (28)
Release of a regulatory liability in 2020 related to 2016-2018 income tax expense forecasting differences (175) (86) (89)
Change in bad debt regulatory assets (84) (51) (33)
TCJA revenue amortization (82) (44) (38)
Increase in prepaid insurance premiums (24)
Net increase in Reserves for Aliso Canyon Costs, current and noncurrent, due to $450 higher accruals and $129 lower payments 579 579
Distributions of earnings from Cameron LNG JV in 2020 365
Change in net undercollected regulatory balancing accounts (including long-term amounts in regulatory assets) 352 29 323
SDG&E’s initial shareholder contribution to the Wildfire Fund in September 2019 323 323
Decrease in funding for the Rabbi Trust 141
Change in net margin posted at Sempra Infrastructure 109
Change in income taxes receivable/payable, net 72 255 345
Change in accounts payable 61 71
Higher distributions of earnings from Oncor Holdings 39
Higher (lower) net income, adjusted for noncash items included in earnings 39 35 (258)
Other 35 (19) 14
Change in net cash flows from discontinued operations primarily due to $1,161 income taxes paid related to the sale of our South American businesses (1,441)
$ (497) $ 299 $ 658
CASH FLOWS FROM INVESTING ACTIVITIES
(Dollars in millions)
Years ended December 31, Sempra SDG&E SoCalGas
2021 $ (5,508) $ (2,213) $ (1,984)
2020 553 (1,934) (1,843)
Change $ (6,061) $ (279) $ (141)
Distribution from Cameron LNG JV $ (753)
Increase in capital expenditures (339) $ (278) $ (141)
Advance to note receivable with KKR (305)
Acquisition of 50% interest in ESJ in March 2021 for $79, net of $14 cash and cash equivalents acquired (65)
Higher proceeds from sale of assets 19
Higher repayments of advances from unconsolidated affiliates 31
Lower contributions to Oncor Holdings 66
Lower advances to unconsolidated affiliates 84
Distribution from Oncor Holdings 2021 361
Other 11 (1)
Change in net cash flows from discontinued operations mainly due to $5,766 proceeds, net of transaction costs, offset by $502 cash sold from the sale of our South American businesses (5,171)
$ (6,061) $ (279) $ (141)
2020 $ 553 $ (1,934) $ (1,843)
2019 (4,593) (1,522) (1,438)
Change $ 5,146 $ (412) $ (405)
Contributions to Oncor Holdings to fund Oncor’s purchase of InfraREIT in May 2019 $ 1,067
Distribution from Cameron LNG JV in 2020 753
Contributions to Peruvian businesses in discontinued operations in 2019 583
Contributions to Chilean businesses in discontinued operations in 2019 394
Acquisition of investment in Sharyland Holdings in May 2019 95
Increase in capital expenditures (968) $ (420) $ (404)
Dividends received from Peruvian businesses in discontinued operations in 2019 (583)
Net proceeds from the April 2019 sale of Sempra Renewables’ wind assets and investments (569)
Dividends received from Chilean businesses in discontinued operations in 2019 (394)
Net proceeds from the February 2019 sale of Sempra Infrastructure’s non-utility natural gas storage assets (322)
Loan to ESJ JV in 2020 (85)
Other (8) 8 (1)
Change in net cash flows from discontinued operations mainly due to $5,766 proceeds, net of transaction costs, offset by $502 cash sold from the sale of our South American businesses 5,183
$ 5,146 $ (412) $ (405)
CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Years ended December 31, Sempra SDG&E SoCalGas
2021 $ 1,260 $ 600 $ 984
2020 (2,373) 797 311
Change $ 3,633 $ (197) $ 673
Change in borrowings and repayments of short-term debt, net $ 3,672 $ 481 $ 789
Proceeds from sale of NCI in KKR in 2021, net of $170 of transaction costs 3,199
Lower payments on short-term debt greater than 90 days 2,125
Lower repurchases of common stock 227
Make-whole premium payments related to early redemptions of debt (121)
(Higher) lower common dividends paid (157) (100) 25
(Lower) higher issuances of short-term debt with maturities greater than 90 days (655) 375
Net proceeds from issuance of series C preferred stock in 2020 (891)
Lower issuances of long-term debt (1,623) (853) (949)
Higher payments on long-term debt and finance leases (1,750) (103)
Equity contribution from Sempra in connection with accruals related to the Leak 800
Other 8 3 8
Change in net cash flows from discontinued operations primarily from a $250 intercompany loan and $165 of net issuances of short-term debt in 2020 (401)
$ 3,633 $ (197) $ 673
2020 $ (2,373) $ 797 $ 311
2019 1,475 405 562
Change $ (3,848) $ 392 $ (251)
Change in borrowings and repayments of short-term debt, net $ (2,415) $ 131 $ (891)
Net proceeds from issuances of common stock from settlement of forward sale agreements in 2019 (1,794)
Higher payments for commercial paper and other short-term debt with maturities greater than 90 days
(1,341)
Higher payments on long-term debt and finance leases (856) (236) (6)
Repurchases of common stock under ASR program in 2020 (500)
Higher repurchases of IEnova stock held by NCI (221)
Lower issuances of short-term debt with maturities greater than 90 days (213)
(Higher) lower common dividends paid (181) (200) 50
Capital contribution from OMEC LLC in 2019 to repay OMEC’s loan (175) (175)
Lower advances from unconsolidated affiliates (91)
Equity contribution from Sempra to fund initial shareholder contribution to the Wildfire Fund in September 2019 (322)
Higher issuances of long-term debt 1,968 1,198 600
Net proceeds from issuance of series C preferred stock 891
Change in intercompany activities with discontinued operations primarily related to intercompany loans in 2019 266
Other 21 (4) (4)
Change in net cash flows from discontinued operations primarily from a $250 intercompany loan and $60 net increase in short-term debt in 2020 and $977 equity contribution from Sempra, offset by $1,380 common dividends paid in 2019 793
$ (3,848) $ 392 $ (251)
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)
Years ended December 31,
2021 2020 2019
SDG&E $ 2,220 $ 1,942 $ 1,522
SoCalGas 1,984 1,843 1,439
Sempra Infrastructure 802 879 736
Sempra Renewables - - 2
Parent and other 9 12 9
Total $ 5,015 $ 4,676 $ 3,708
Expenditures for Investments and Acquisitions
The following table summarizes by segment our investments in various JVs, as well as business and asset acquisitions.
EXPENDITURES FOR INVESTMENTS AND ACQUISITIONS
(Dollars in millions)
Years ended December 31,
2021 2020 2019
Sempra Texas Utilities $ 566 $ 648 $ 1,685
Sempra Infrastructure 67 4 110
Parent and other - - 2
Total $ 633 $ 652 $ 1,797
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 2022, we expect to make capital expenditures and investments of approximately $6.2 billion (which excludes capital expenditures that will be funded by unconsolidated entities), as summarized by segment in the following table.
FUTURE CAPITAL EXPENDITURES AND INVESTMENTS
(Dollars in millions)
Year ended December 31, 2022
SDG&E $ 2,700
SoCalGas 2,100
Sempra Texas Utilities 400
Sempra Infrastructure 1,000
Total $ 6,200
We expect the majority of our capital expenditures and investments in 2022 will relate to transmission and distribution improvements at our regulated public utilities, and construction of the ECA LNG Phase 1 liquefaction export project at Sempra Infrastructure.
From 2022 through 2026, 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 $24.4 billion (which excludes capital expenditures that will be funded by unconsolidated entities), as follows: $11.4 billion at SDG&E, $9.8 billion at SoCalGas, $1.1 billion at Sempra Texas Utilities and $2.1 billion at Sempra Infrastructure. Capital expenditure amounts include capitalized interest and AFUDC related to debt.
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 U.S. federal tax law and business opportunities providing desirable rates of return. See “Part I - Item 1A. Risk Factors” for a discussion of 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)
2021 2020 2019
SDG&E $ 12,527 $ 11,109 $ 10,467
SoCalGas $ 9,371 $ 8,228 $ 7,401
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 2022 based on our expected capital investments.
Capital Stock Transactions
Sempra
Cash provided by issuances of common and preferred stock was:
▪$5 million in 2021
▪$902 million in 2020
▪$1.8 billion in 2019
IEnova Exchange Offer and Cash Tender Offer. In May 2021, we acquired 381,015,194 publicly owned shares of IEnova in exchange for 12,306,777 newly issued shares of our common stock upon completion of our exchange offer launched in the U.S. and Mexico, which increased our ownership interest in IEnova from 70.2% to 96.4%. In September 2021, we completed a cash tender offer and acquired 51,014,545 publicly owned shares of IEnova for 4.0 billion Mexican pesos (approximately $202 million in U.S. dollars) in cash, which increased our ownership interest in IEnova from 96.4% to 99.9%. We describe these transactions in Note 1 of the Notes to Consolidated Financial Statements.
In addition to being traded on the New York Stock Exchange, Sempra’s common stock is also listed on the Mexican Stock Exchange under the trading symbol SRE.MX. IEnova’s shares were delisted from the Mexican Stock Exchange effective October 15, 2021. In connection with the delisting, we are maintaining a trust for the purpose of purchasing the 1,212,981 IEnova shares that remained publicly owned as of the completion of the cash tender offer for 78.97 Mexican pesos per share, the same price per share that was offered in our cash tender offer. The trust will be in place through the earlier of April 14, 2022 or the date on which we acquire all remaining publicly owned IEnova shares. As of February 16, 2022, an aggregate of 629,784 of the remaining publicly owned IEnova shares had been acquired by such trust.
Sempra Common Stock Repurchases. As we discuss in Note 14 of the Notes to Consolidated Financial Statements, in November and December of 2021, we entered into and completed an open market repurchase program under which we paid $300 million to repurchase 2,422,758 shares of our common stock at a weighted-average purchase price of $123.83 per share, excluding commissions. We repurchased an additional 1,472,756 shares of our common stock for $200 million pursuant to an ASR program that was completed on February 11, 2022. These share repurchases were funded with commercial paper borrowings that we plan to repay with a portion of the anticipated proceeds from the sale of NCI in SI Partners to ADIA, which we expect to close in the summer of 2022 subject to the receipt of certain regulatory and third-party approvals and other customary closing conditions.
Dividends
Sempra
Sempra paid cash dividends of:
▪$1,331 million for common stock and $99 million for preferred stock in 2021
▪$1,174 million for common stock and $157 million for preferred stock in 2020
▪$993 million for common stock and $142 million for preferred stock in 2019
Dividends declared on common stock have increased in each of the last three years due to an increase in the per-share quarterly dividends approved by our board of directors to $1.10 in 2021 ($4.40 annually) from $1.045 in 2020 ($4.18 annually) and from $0.9675 in 2019 ($3.87 annually).
On February 24, 2022, our board of directors approved an increase in Sempra’s quarterly common stock dividend to $1.145 per share ($4.58 annually), the first of which is payable April 15, 2022. In addition, on February 24, 2022, our board of directors declared semi-annual dividends of $24.375 per share on our series C preferred stock, payable on April 15, 2022. 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 declared on an annual historical basis, including recent historical increases and annualized dividends for the current fiscal year, may not be indicative of future declarations.
SDG&E
In 2021 and 2020, SDG&E paid common stock dividends to Enova and Enova paid corresponding dividends to Sempra of $300 million and $200 million, respectively. SDG&E did not declare or pay common stock dividends in 2019. 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 2021, 2020 and 2019, SoCalGas paid common stock dividends to PE and PE paid corresponding dividends to Sempra of $75 million, $100 million and $150 million, respectively. 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, 2021, based on these regulations, Sempra could have received combined loans and dividends of approximately $798 million from SDG&E and $445 million from SoCalGas.
We provide additional information about dividend restrictions in “Restricted Net Assets” in Note 1 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:
▪$79.17 in 2021
▪$70.11 in 2020
▪$60.58 in 2019
The increase in 2021 was primarily due to 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 KKR, the IEnova exchange offer and
subsequent cash tender offer, and the common shares issued from the conversion of series A preferred stock and series B preferred stock. In 2020, the increase was primarily due to comprehensive income exceeding dividends, offset by common stock repurchases.
Capitalization
Our debt to capitalization ratio, calculated as total debt as a percentage of total debt and equity, was as follows:
TOTAL CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIOS
(Dollars in millions)
Sempra SDG&E SoCalGas
December 31, 2021
Total capitalization $ 52,064 $ 16,655 $ 10,611
Debt-to-capitalization ratio 47 % 50 % 49 %
December 31, 2020
Total capitalization $ 49,140 $ 15,207 $ 10,030
Debt-to-capitalization ratio 49 % 49 % 49 %
December 31, 2019
Total capitalization $ 47,621 $ 13,542 $ 9,172
Debt-to-capitalization ratio 54 % 48 % 48 %
Significant changes in 2021 that affected capitalization included the following:
▪Sempra: decrease in long-term debt, offset by an increase in short-term debt and increase in equity primarily from the sale of NCI.
▪SDG&E: increase in short-term and long-term debt and increase in equity from comprehensive income exceeding dividends.
▪SoCalGas: decrease in equity from comprehensive loss, offset by equity contributions from Sempra 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 provide the opportunity to earn a reasonable 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 ACCOUNTING
Sempra, SDG&E
We record derivative instruments for which we do not apply a scope exception at fair value on the Consolidated Balance Sheets. We also use the normal purchase or sale exception for certain derivative contracts, which is applied on a contract-by-contract basis. Changes in assumed physical delivery on contracts for which we elected normal purchase or sale accounting may result in “tainting” of the election, which may preclude us from making this election in future transactions, thereby impacting Sempra’s and/or SDG&E’s results of operations. The impacts of derivatives accounting on SDG&E’s results of operations are typically not significant because regulatory accounting principles generally apply to its contracts. We provide details of our derivative instruments and our fair value approaches in Notes 11 and 12, respectively, of the Notes to Consolidated Financial Statements.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Sempra, SDG&E, SoCalGas
To measure our pension and other postretirement benefit 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
▪mortality rates
▪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 other postretirement benefits, 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, accumulated benefit obligation for PBOP, and projected benefit costs, in each case if the discount rate or assumed rate of return on plan assets were changed by 100 bps at December 31, 2021:
IMPACT DUE TO INCREASE/DECREASE IN DISCOUNT RATE
(Dollars in millions)
Sempra SDG&E SoCalGas
Increase Decrease Increase Decrease Increase Decrease
Pension:
(Decrease) increase to projected benefit obligation,
net
$ (432) $ 493 $ (55) $ 58 $ (356) $ 411
(Decrease) increase to net periodic benefit cost (24) 25 3 (2) (27) 27
PBOP:
(Decrease) increase to accumulated benefit
obligation, net
(122) 157 (24) 30 (95) 123
(Decrease) increase to net periodic benefit cost (9) 10 (2) 2 (7) 8
IMPACT DUE TO INCREASE/DECREASE IN RETURN ON PLAN ASSETS
(Dollars in millions)
Sempra SDG&E SoCalGas
Increase Decrease Increase Decrease Increase Decrease
Pension:
(Decrease) increase to net periodic benefit cost $ (27) $ 27 $ (8) $ 8 $ (17) $ 17
PBOP:
(Decrease) increase to net periodic benefit cost (13) 13 (2) 2 (10) 10
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 other postretirement benefit plans in Note 9 of the Notes to Consolidated Financial Statements.
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 $568 million as of December 31, 2021, 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:
INCREASE TO ARO AND REGULATORY ASSET
(Dollars in millions)
December 31, 2021
Uniform increase in escalation percentage of 1 percentage point $ 91
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 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 the 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 2021 and 2020, 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 was substantially above their carrying value for each year as of October 1, our goodwill impairment testing date.
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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.
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 power and natural gas derivatives to manage electric and natural gas price risk associated with servicing load requirements. The use of power and natural gas derivatives is subject to certain limitations imposed by company policy and is in compliance with risk management and trading activity plans that have been filed with and approved by the CPUC. 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, 2021 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 generally exposed to commodity price risk indirectly through its LNG, natural gas pipelines and storage, and power-generating assets. This segment may utilize commodity transactions in an effort to optimize 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. A hypothetical 10% unfavorable change in commodity prices would have resulted in a change in the fair value of our commodity-based natural gas and electricity derivatives of $3 million and $4 million at December 31, 2021 and 2020, 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 and SoCalGas’ commodity positions were $5 million and $1 million, respectively, at December 31, 2021 and $3 million and negligible, respectively, at December 31, 2020.
INTEREST RATE RISK
We are exposed to fluctuations in interest rates primarily as a result of our having issued 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)
December 31, 2021 December 31, 2020
December 31, 2019
Sempra
SDG&E SoCalGas Sempra
SDG&E SoCalGas Sempra
SDG&E SoCalGas
Short-term:
Sempra California $ 1,161 $ 776 $ 385 $ 113 $ - $ 113 $ 710 $ 80 $ 630
Other 2,310 - - 772 - - 2,798 - -
Long-term:
Sempra California fixed-rate $ 10,876 $ 6,417 $ 4,459 $ 10,512 $ 6,053 $ 4,459 $ 8,949 $ 5,140 $ 3,809
Sempra California variable-rate 300 - 300 500 200 300 - - -
Other fixed-rate 8,591 - - 11,204 - - 11,561 - -
Other variable-rate 341 - - 51 - - 746 - -
(1) After the effects of interest rate swaps. Before the effects of acquisition-related fair value adjustments and 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 that would result from a hypothetical change in market interest rates. Earnings 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, 2021 increased or decreased by 10%, the change in earnings over the 12-month period ending December 31, 2022 would be approximately $1 million. If interest rates increased or decreased by 10% on all variable-rate long-term debt at December 31, 2021, after considering the effects of interest rate swaps, the change in earnings over the 12-month period ending December 31, 2022 would be approximately $1 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, other postretirement benefit 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 AND INFLATION RATE RISK
We discuss our foreign currency and inflation exposures 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:
HYPOTHETICAL EFFECTS FROM 10% STRENGTHENING OF U.S. DOLLAR (1)
(Dollars in millions)
Hypothetical effects
Translation of 2021 earnings to U.S. dollars(2)
$ (3)
Transactional exposure(3)
Translation of net assets of foreign subsidiaries and investment in foreign entities(4)
(18)
(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, 2021 on monetary assets and liabilities and translation 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, 2021 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 $4.8 billion, including those related to our investments in JVs, at December 31, 2021, the hypothetical effect of a 10% increase in the Mexican inflation rate is approximately $111 million lower earnings as a result of higher income tax expense for our consolidated subsidiaries, as well as lower equity earnings for our JVs.
We completed the sales of our South American businesses in 2020 and are no longer exposed to changes in foreign currency and inflation rates in Peru and Chile.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements are listed on the Index to Consolidated Financial Statements set forth on page of this annual report on Form 10-K.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
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, 2021, 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, 2021. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2021, as stated in their reports, which are included in this annual report on Form 10-K.
In April 2021, SDG&E implemented a new customer information system to replace its legacy system. The system has been designed and implemented to provide customers an enhanced digital experience and enhance the overall system of internal control over financial reporting through further automation and integration of business processes, including revenue. In connection with the implementation, SDG&E performed pre-implementation planning, design and testing of internal controls that became effective in the second quarter of 2021. In the fourth quarter of 2021, SDG&E completed its post-implementation monitoring and process modifications in order to maintain an effective control framework. Other than these post-implementation activities in connection with SDG&E’s new customer information system, 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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Sempra Energy:
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Sempra Energy and subsidiaries (“Sempra”) as of December 31, 2021, 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, 2021, 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, 2021 of Sempra and our report dated February 25, 2022 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
San Diego, California
February 25, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2021, 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, 2021, 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, 2021 of SDG&E and our report dated February 25, 2022 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
San Diego, California
February 25, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2021, 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, 2021, 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, 2021 of SoCalGas and our report dated February 25, 2022 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
San Diego, California
February 25, 2022

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
We provide the information required by Item 401 of SEC Regulation S-K, as required by this item, with respect to executive officers of Sempra and SoCalGas in “Part I - Item 1. Business - Other Matters - Information About Our Executive Officers.” All other information required by this item is incorporated by reference from “Corporate Governance” and “Proposal 1: Election of Directors” in the proxy statement to be filed for the May 2022 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2022 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from “Executive Compensation,” including “Compensation Discussion and Analysis,” “Compensation and Talent Committee Report” and “Compensation Tables,” in the proxy statement to be filed for the May 2022 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2022 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
Sempra has LTIPs that permit the grant of a wide variety of equity and equity-based incentive awards to directors, officers and key employees. At December 31, 2021, outstanding awards consisted of stock options and RSUs held by 425 employees.
The following table sets forth information regarding our equity compensation plans at December 31, 2021.
EQUITY COMPENSATION PLANS
Equity compensation plans approved by shareholders Number of shares to be issued upon exercise of outstanding options, warrants and rights(1)
Weighted-average exercise price of outstanding options, warrants and rights(2)
Number of additional shares remaining available for future issuance(3)
2013 LTIP 568,935 $ 106.76 -
2019 LTIP 1,116,486 $ 132.77 5,986,241
(1) The 2013 LTIP consists of 192,506 options to purchase shares of our common stock, all of which were granted at an exercise price equal to 100% of the grant date fair market value of the shares subject to the option, 334,492 performance-based RSUs and 41,937 service-based RSUs. The 2019 LTIP consists of 344,838 options to purchase shares of our common stock, all of which were granted at an exercise price equal to 100% of the grant date fair market value of the shares subject to the option, 536,285 performance-based RSUs and 235,363 service-based RSUs. Each performance-based RSU granted under the 2013 LTIP and the 2019 LTIP represents the right to receive from zero to 2.0 shares of our common stock if applicable performance conditions are satisfied. For purposes of this table, the number of shares of common stock shown to be subject to each performance-based RSU is 1.0 share, which assumes performance conditions are satisfied at the target level.
(2) Represents the weighted-average exercise price of the 192,506 and 344,838 outstanding options to purchase shares of our common stock under the 2013 LTIP and the 2019 LTIP, respectively.
(3) The number of shares available for future issuance is increased by the number of shares to which each participant would otherwise be entitled that are withheld or surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards, and is also increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares. No new awards may be granted under the 2013 LTIP.
We provide additional discussion of share-based compensation in Note 10 of the Notes to Consolidated Financial Statements.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information required by Item 403 of SEC Regulation S-K, as required by this item, is incorporated by reference from “Share Ownership” in the proxy statement to be filed for the May 2022 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2022 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated by reference from “Corporate Governance” in the proxy statement to be filed for the May 2022 annual meeting of shareholders for Sempra and from the information statement to be filed for the June 2022 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services is presented below for Sempra, SDG&E and SoCalGas. The following table shows the fees paid to Deloitte & Touche LLP, the independent registered public accounting firm for Sempra, SDG&E and SoCalGas, for services provided for 2021, 2020 and 2019.
PRINCIPAL ACCOUNTANT FEES
(Dollars in thousands)
Sempra SDG&E SoCalGas
Fees Percent of total Fees Percent of total Fees Percent of total
2021:
Audit fees:
Consolidated financial statements, internal controls audits and subsidiary audits
$ 10,166 $ 2,753 $ 3,486
Regulatory filings and related services 807 60 -
Total audit fees 10,973 81 % 2,813 87 % 3,486 91 %
Audit-related fees:
Employee benefit plan audits 520 184 309
Other audit-related services(1)
1,840 119 -
Total audit-related fees 2,360 17 303 9 309 8
Tax fees(2)
272 2 113 4 33 1
All other fees(3)
13 - - - 8 -
Total fees $ 13,618 100 % $ 3,229 100 % $ 3,836 100 %
2020:
Audit fees:
Consolidated financial statements, internal controls audits and subsidiary audits
$ 9,145 $ 2,469 $ 3,023
Regulatory filings and related services 827 100 55
Total audit fees 9,972 82 % 2,569 86 % 3,078 90 %
Audit-related fees:
Employee benefit plan audits 505 183 307
Other audit-related services(1)
1,494 137 -
Total audit-related fees 1,999 17 320 11 307 9
Tax fees(2)
156 1 111 3 32 1
All other fees(3)
22 - - - - -
Total fees $ 12,149 100 % $ 3,000 100 % $ 3,417 100 %
2019:
Audit fees:
Consolidated financial statements, internal controls audits and subsidiary audits
$ 10,568 $ 2,804 $ 2,789
Regulatory filings and related services 466 45 45
Total audit fees 11,034 87 % 2,849 89 % 2,834 91 %
Audit-related fees:
Employee benefit plan audits 517 162 286
Other audit-related services(1)
883 99 10
Total audit-related fees 1,400 11 261 8 296 9
Tax fees(2)
74 1 73 3 - -
All other fees(3)
74 1 15 - - -
Total fees $ 12,582 100 % $ 3,198 100 % $ 3,130 100 %
(1) Other audit-related services in 2021 and 2019 primarily relate to statutory audits and agreed upon procedures. Other audit-related services in 2020 primarily relate to statutory audits, agreed upon procedures and permitted internal control advisory services.
(2) Tax fees in 2021 and 2020 relate to tax consulting and compliance services. Tax fees in 2019 relate to tax consulting services.
(3) All other fees relate to training and conferences.
The Audit Committee of Sempra’s board of directors is directly responsible for the appointment, compensation, retention and oversight, including the oversight of the audit fee negotiations, of the independent registered public accounting firm for Sempra and its subsidiaries, including SDG&E and SoCalGas. As a matter of good corporate governance, each of the Sempra, SDG&E and SoCalGas boards of directors reviewed the performance of Deloitte & Touche LLP and appointed them as the independent registered public accounting firm for each of Sempra, SDG&E and SoCalGas, respectively. Sempra’s board of directors has determined that each member of its Audit Committee is an independent director and is financially literate, and that Mr. Jack T. Taylor, who chairs the committee, and Ms. Cynthia L. Walker, who is a member of the committee, are audit committee financial experts as defined by the rules of the SEC.
Except where pre-approval is not required by SEC rules, Sempra’s Audit Committee pre-approves all audit, audit-related and permissible non-audit services provided by Deloitte & Touche LLP for Sempra and its subsidiaries, including all services provided by Deloitte & Touche LLP for Sempra, SDG&E and SoCalGas in 2021, 2020 and 2019. The committee’s pre-approval policies and procedures provide for the general pre-approval of specific types of services and give detailed guidance to management as to the services that are eligible for general pre-approval, and they require specific pre-approval of all other permitted services. For both types of pre-approval, the committee considers whether the services to be provided are consistent with maintaining the firm’s independence. The committee’s policies and procedures also delegate authority to the chair of the committee to address any requests for pre-approval of services between committee meetings, with any pre-approval decisions to be reported to the committee at its next scheduled meeting.
PART IV.

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
1. FINANCIAL STATEMENTS
Our consolidated financial statements are listed on the Index to Consolidated Financial Statements set forth on page of this annual report on Form 10-K.
2. FINANCIAL STATEMENT SCHEDULES
Schedule I is listed on the Index to Condensed Financial Information of Parent as set forth on page S-1 of this annual report on Form 10-K.
Any other schedule for which provision is made in SEC Regulation S-X is not required under the instructions contained therein, is inapplicable or the information is included in the Consolidated Financial Statements and Notes thereto in this annual report on Form 10-K.
3. EXHIBITS
EXHIBIT INDEX
The exhibits listed below relate to each registrant as indicated. Unless otherwise indicated, the exhibits that are incorporated by reference herein were filed under File Number 1-14201 (Sempra Energy), File Number 1-40 (Pacific Lighting Corporation), File Number 1-03779 (San Diego Gas & Electric Company) and/or File Number 1-01402 (Southern California Gas Company).
EXHIBIT INDEX
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
EXHIBIT 2 -- PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION OR SUCCESSION
Sempra Energy
2.1 Purchase and Sale Agreement, dated as of September 27, 2019, by and between Sempra International Holdings N.V. and China Yangtze Power International (Hongkong) Co., Limited.
8-K 2.1 09/30/19
2.2 Letter of Undertaking, dated as of September 27, 2019, by and between Sempra Energy International Holdings N.V., China Three Gorges Corporation and Ching Three Gorges Construction Management Co., Ltd.
8-K 2.2 09/30/19
2.3 Purchase and Sale Agreement, dated as of October 12, 2019, by and between Sempra Energy International Holdings N.V. and State Grid International Development Limited.
8-K 2.1 10/15/19
EXHIBIT 3 -- BYLAWS AND ARTICLES OF INCORPORATION
Sempra Energy
3.1 Amended and Restated Articles of Incorporation of Sempra Energy effective May 23, 2008.
10-K 3.1 02/27/20
3.2 Bylaws of Sempra Energy (as amended through April 14, 2020).
8-K 3.1 04/14/20
3.3 Certificate of Determination of Preferences of the 6% Mandatory Convertible Preferred Stock, Series A, of Sempra Energy (including the form of certificate representing the 6% Mandatory Convertible Preferred Stock, Series A), filed with the Secretary of State of the State of California and effective January 5, 2018.
8-K 3.1 01/09/18
3.4 Certificate of Determination of Preferences of the 6.75% Mandatory Convertible Preferred Stock, Series B, of Sempra Energy (including the form of certificate representing the 6.75% Mandatory Convertible Preferred Stock, Series B), filed with the Secretary of State of the State of California and effective July 11, 2018.
8-K 3.1 07/13/18
3.5 Certificate of Determination of Preferences of 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Stock, Series C, of Sempra Energy (including the form of certificate representing the 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, Series C), filed with the Secretary of State of California and effective June 11, 2020.
8-K 3.1 06/15/20
San Diego Gas & Electric Company
3.6 Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company effective August 15, 2014.
10-K 3.4 02/26/15
3.7 Bylaws of San Diego Gas & Electric (as amended through October 26, 2016).
10-Q 3.1 11/02/16
EXHIBIT INDEX (CONTINUED)
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
Southern California Gas Company
3.8 Restated Articles of Incorporation of Southern California Gas Company effective October 7, 1996.
10-K 3.01 03/28/97
3.9 Bylaws of Southern California Gas Company (as amended through January 30, 2017).
8-K 3.1 01/31/17
EXHIBIT 4 -- INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES
Certain instruments defining the rights of holders of long-term debt instruments are not required to be filed or incorporated by reference herein pursuant to Item 601(b)(4)(iii)(A) of SEC Regulation S-K. Each registrant agrees to furnish a copy of such instruments to the SEC upon request.
Sempra Energy
4.1 Description of rights of Sempra Energy Common Stock (Amended and Restated Articles of Incorporation of Sempra Energy effective May 23, 2008) (included as Exhibit 3.1 above).
10-K 3.1 02/27/20
4.2 Description of Securities.
X
4.3 Certificate of Determination of Preferences of the 6% Mandatory Convertible Preferred Stock, Series A, of Sempra Energy (including the form of certificate representing the 6% Mandatory Convertible Preferred Stock, Series A), filed with the Secretary of State of the State of California and effective January 5, 2018 (included as Exhibit 3.3 above).
8-K 3.1 01/09/18
4.4 Certificate of Determination of Preferences of the 6.75% Mandatory Convertible Preferred Stock, Series B, of Sempra Energy (including the form of certificate representing the 6.75% Mandatory Convertible Preferred Stock, Series B) filed with the Secretary of State of California and effective July 11, 2018 (included as Exhibit 3.4 above).
8-K 3.1 07/13/18
4.5 Certificate of Determination of Preferences of 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Stock, Series C, of Sempra Energy (including the form of certificate representing the 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, Series C), filed with the Secretary of State of California and effective June 11, 2020 (included as Exhibit 3.5 above).
8-K 3.1 06/15/20
4.6 Indenture dated as of February 23, 2000, between Sempra Energy and U.S. Bank Trust National Association, as Trustee.
S-3ASR
333-153425 4.1 09/11/08
4.7 Officers’ Certificate of Sempra Energy, including the form of its 6.00% Note due 2039.
8-K 4.1 10/08/09
4.8 Officers’ Certificate of Sempra Energy, including the form of its 3.250% Note due 2027.
8-K 4.1 06/09/17
4.9 Officers’ Certificate of Sempra Energy, including the forms of its 2.900% Note due 2023, 3.400% Note due 2028, 3.800% Note due 2038, and 4.000% Note due 2048.
8-K 4.1 01/12/18
4.10 Subordinated Indenture, dated as of June 26, 2019, between Sempra Energy and U.S. Bank National Association, as trustee.
8-K 4.2 06/26/19
4.11 Officers’ Certificate of Sempra Energy, including the form of its 5.750% Junior Subordinated Note due 2079.
8-K 4.1 06/26/19
4.12 Officer’s Certificate of Sempra Energy, including the form of its 4.125% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2052.
8-K 4.1 11/19/21
EXHIBIT INDEX (CONTINUED)
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
Southern California Gas Company
4.13 Description of preferences of Preferred Stock, Preference Stock and Series Preferred Stock (Southern California Gas Company Restated Articles of Incorporation) (included as Exhibit 3.8 above).
10-K 3.01 03/28/97
4.14 Description of Securities.
10-K 4.9 02/27/20
Sempra Energy / San Diego Gas & Electric Company
4.15 Mortgage and Deed of Trust dated July 1, 1940. 2-4769 B-3 (1)
4.16 Second Supplemental Indenture dated as of March 1, 1948. 2-7418 B-5B (1)
4.17 Ninth Supplemental Indenture dated as of August 1, 1968. 333-52150 4.5 (1)
4.18 Tenth Supplemental Indenture dated as of December 1, 1968. 2-36042 2-K (1)
4.19 Sixteenth Supplemental Indenture dated August 28, 1975. 33-34017 4.2 (1)
4.20 Fiftieth Supplemental Indenture, dated as of May 19, 2005.
8-K 4.1 05/19/05
4.21 Fifty-Second Supplemental Indenture, dated as of June 8, 2006.
8-K 4.1 06/08/06
4.22 Fifty-Fourth Supplemental Indenture, dated as of September 20, 2007.
8-K 4.1 09/20/07
4.23 Fifty-Fifth Supplemental Indenture, dated as of May 14, 2009.
8-K 4.1 05/15/09
4.24 Fifty-Sixth Supplemental Indenture, dated as of May 13, 2010.
8-K 4.1 05/13/10
4.25 Fifty-Seventh Supplemental Indenture, dated as of August 26, 2010.
8-K 4.1 08/26/10
4.26 Fifty-Eighth Supplemental Indenture, dated as of August 18, 2011.
8-K 4.1 08/18/11
4.27 Sixtieth Supplemental Indenture, dated as of November 17, 2011.
8-K 4.1 11/17/11
4.28 Sixty-First Supplemental Indenture, dated as of March 22, 2012.
8-K 4.1 03/23/12
4.29 Sixty-Second Supplemental Indenture, dated as of September 9, 2013.
8-K 4.1 09/09/13
4.30 Sixty-Fourth Supplemental Indenture, dated as of March 12, 2015.
8-K 4.2 03/12/15
4.31 Sixty-Fifth Supplemental Indenture, dated as of May 19, 2016.
8-K 4.1 05/19/16
4.32 Sixty-Sixth Supplemental Indenture, dated as of June 8, 2017.
8-K 4.1 06/08/17
4.33 Sixty-Seventh Supplemental Indenture, dated as of May 17, 2018.
8-K 4.1 05/17/18
4.34 Sixty-Eighth Supplemental Indenture, dated as of May 31, 2019.
8-K 4.1 05/31/19
4.35 Sixty-Ninth Supplemental Indenture, dated as of April 7, 2020.
8-K 4.1 04/07/20
4.36 Seventieth Supplemental Indenture, dated as of September 28, 2020.
8-K 4.1 09/28/20
4.37 Seventy-First Supplemental Indenture, dated as of August 13, 2021.
8-K 4.1 08/13/21
(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates the SEC’s Electronic Data Gathering, Analysis, and Retrieval (EDGAR) database.
EXHIBIT INDEX (CONTINUED)
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
Sempra Energy / Southern California Gas Company
4.38 First Mortgage Indenture of Southern California Gas Company to American Trust Company dated October 1, 1940. 2-4504 B-4 (1)
4.39 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955. 2-11997 4.07 (1)
4.40 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of December 1, 1956.
10-K 4.09 02/23/07
4.41 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank dated as of June 1, 1965.
10-K 4.10 02/23/07
4.42 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972. 2-59832 2.19 (1)
4.43 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976. 2-56034 2.20 (1)
4.44 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981. 333-70654 4.24 (1)
4.45 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of November 18, 2005.
8-K 4.1 11/18/05
4.46 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of November 18, 2010.
8-K 4.1 11/18/10
4.47 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of September 21, 2012.
8-K 4.1 09/21/12
4.48 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of March 13, 2014.
8-K 4.1 03/13/14
4.49 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of September 11, 2014.
8-K 4.1 09/11/14
4.50 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of June 18, 2015.
8-K 4.2 06/18/15
4.51 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of June 3, 2016.
8-K 4.1 06/03/16
4.52 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of May 15, 2018.
8-K 4.1 05/15/18
4.53 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of September 24, 2018.
8-K 4.1 09/24/18
4.54 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of June 4, 2019.
8-K 4.1 06/04/19
4.55 Supplemental Indenture of Southern California Gas Company to U.S. National Bank Association, dated as of January 9, 2020.
8-K 4.1 01/09/20
4.56 Indenture, dated as of May 1, 1989, between Southern California Gas Company and Citibank, N.A., as trustee. 333-28260 4.1.1 (1)
(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates the SEC’s Electronic Data Gathering, Analysis, and Retrieval (EDGAR) database.
EXHIBIT INDEX (CONTINUED)
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
4.57 First Supplemental Indenture, dated as of October 1, 1992, between Southern California Gas Company and Citibank, N.A., as trustee. 8-K 4.1.2 (1)
4.58 Form of 5.670% Medium Term Note due 2028. 8-K 4.2.1 (1)
4.59 Senior Indenture, dated as of September 21, 2020, between Southern California Gas Company and U.S. Bank National Association, as trustee.
8-K 4.1 09/21/20
4.60 Officers’ Certificate of Southern California Gas Company, including the form of its Floating Rate Note due 2023.
8-K 4.2 09/21/20
EXHIBIT 10 -- MATERIAL CONTRACTS
Sempra Energy
10.1* Amended and Restated Engineering, Procurement and Construction Contract, dated as of December 11, 2020, between Port Arthur LNG, LLC and PALNG Common Facilities Company, LLC (but only for the limited purpose set forth therein), and Bechtel Oil, Gas and Chemicals, Inc.
10-K 10.1 02/25/21
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
10.2 Form of Continental Forge and California Class Action Price Reporting Settlement Agreement dated as of January 4, 2006.
8-K 99.1 01/05/06
Sempra Energy / San Diego Gas & Electric Company
10.3 Amended and Restated Operating Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011.
10-Q 10.4 05/09/11
10.4 Amended and Restated Servicing Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011.
10-Q 10.5 05/09/11
Sempra Energy / Southern California Gas Company
10.5 Master Agreement to Resolve JCCP No. 4861 Private Party Claims, effective September 26, 2021, by and among Sempra Energy, Southern California Gas Company, and the plaintiff’s law firms listed on the signature pages thereto.
8-K 10.1 09/27/21
Management Contract or Compensatory Plan, Contract or Arrangement
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
10.6 Form of Sempra Energy 2019 Long-Term Incentive Plan 2021 and 2022 Nonqualified Stock Option Award Agreement.
10-K 10.6 02/25/21
10.7 Form of Sempra Energy 2019 Long-Term Incentive Plan 2021 and 2022 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.
10-K 10.7 02/25/21
10.8 Form of Sempra Energy 2019 Long-Term Incentive Plan 2021 and 2022 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Index.
10-K 10.8 02/25/21
10.9 Form of Sempra Energy 2019 Long-Term Incentive Plan 2021 and 2022 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure-S&P 500 Utilities Index.
10-K 10.9 02/25/21
10.10 Form of Sempra Energy 2019 Long-Term Incentive Plan 2020 Nonqualified Stock Option Award Agreement.
10-K 10.5 02/27/20
10.11 Form of Sempra Energy 2019 Long-Term Incentive Plan 2020 Time-Based Restricted Stock Unit Award - Three Year Ratable Vest.
10-K 10.6 02/27/20
* Portions of the exhibit have been omitted in accordance with applicable SEC rules.
(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates EDGAR.
EXHIBIT INDEX (CONTINUED)
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
10.12 Form of Sempra Energy 2019 Long-Term Incentive Plan 2020 Time-Based Restricted Stock Unit Award - Four Year Award Vest.
10-Q 10.1 11/05/20
10.13 Form of Sempra Energy 2019 Long-Term Incentive Plan 2020 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.
10-K 10.7 02/27/20
10.14 Form of Sempra Energy 2019 Long-Term Incentive Plan 2020 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Index.
10-K 10.8 02/27/20
10.15 Form of Sempra Energy 2019 Long-Term Incentive Plan 2020 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Utilities Index.
10-K 10.9 02/27/20
10.16 Sempra Energy 2019 Long-Term Incentive Plan.
DEF 14A E 03/22/19
10.17 Form of Sempra Energy 2019 Long-Term Incentive Plan 2019 Time-Based Restricted Stock Unit Award - Five Year Vest.
10-Q 10.2 08/02/19
10.18 Form of Sempra Energy 2013 Long-Term Incentive Plan 2019 Time-Based Restricted Stock Unit Award - One Year Vest.
10-Q 10.5 08/02/19
10.19 Form of Sempra Energy 2013 Long-Term Incentive Plan 2019 Nonqualified Stock Option Award Agreement.
10-Q 10.1 05/07/19
10.20 Form of Sempra Energy 2013 Long-Term Incentive Plan 2019 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.
10-Q 10.2 05/07/19
10.21 Form of Sempra Energy 2013 Long-Term Incentive Plan 2019 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Index.
10-Q 10.3 05/07/19
10.22 Form of Sempra Energy 2013 Long-Term Incentive Plan 2019 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Utilities Index.
10-Q 10.4 05/07/19
10.23 Form of Sempra Energy 2013 Long-Term Incentive Plan 2019 Time-Based Restricted Stock Unit Award - Ratable vesting.
10-Q 10.5 05/07/19
10.24 Form of Indemnification Agreement with Directors and Executive Officers (executed before January 2011).
10-Q 10.2 08/07/08
10.25 Form of Indemnification Agreement with Directors and Executive Officers (executed after January 2011).
10-Q 10.1 05/04/16
10.26 Form of Sempra Energy Shared Services Executive Incentive Compensation Plan.
10-K 10.19 02/27/14
10.27 Amendment Number 1 to the Amended and Restated Sempra Energy 2013 Long-Term Incentive Plan.
10-K 10.26 02/25/21
10.28 Amended and Restated Sempra Energy 2013 Long-Term Incentive Plan.
10-K 10.5 02/26/16
10.29 Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Index.
10-Q 10.8 05/07/18
10.30 Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Performance-Based Restricted Stock Unit Award - Relative Total Shareholder Return Performance Measure - S&P 500 Utilities Index.
10-Q 10.9 05/07/18
EXHIBIT INDEX (CONTINUED)
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
10.31 Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Performance-Based Restricted Stock Unit Award - EPS Growth Performance Measure.
10-Q 10.10 05/07/18
10.32 Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Time-Based Restricted Stock Unit Award - Cliff vest.
10-Q 10.11 05/07/18
10.33 Form of Sempra Energy 2013 Long-Term Incentive Plan 2018 Special Time-Based Restricted Stock Unit Award - Multi-year vest.
10-Q 10.13 05/07/18
10.34 Amended and Restated Sempra Energy 2005 Deferred Compensation Plan, now known as Sempra Energy Employee and Director Savings Plan.
10-K 10.33 02/25/21
10.35 Amended and Restated Sempra Energy Deferred Compensation and Excess Savings Plan.
10-K 10.28 02/28/17
10.36 2009 Amendment and Restatement of the Sempra Energy Supplemental Executive Retirement Plan effective July 1, 2009.
10-K 10.28 02/26/16
10.37 First Amendment to the 2009 Amendment and Restatement of the Sempra Energy Supplemental Executive Retirement Plan effective February 11, 2010.
10-K 10.29 02/26/16
10.38 Second Amendment to the 2009 Amendment and Restatement of the Sempra Energy Supplemental Executive Retirement Plan effective January 1, 2014.
10-K 10.43 02/26/15
10.39 2015 Amendment and Restatement of the Sempra Energy Cash Balance Restoration Plan effective November 10, 2015.
10-K 10.31 02/26/16
10.40 Sempra Energy Amended and Restated Executive Life Insurance Plan.
10-K 10.22 02/26/13
10.41 Sempra Energy Executive Personal Financial Planning Program Policy Document.
10-K 10.35 02/27/20
Sempra Energy
10.42 Form of Sempra Energy 2019 Long-Term Incentive Plan Non-Employee Directors’ Annual Restricted Stock Unit Award.
10-Q 10.3 08/02/19
10.43 Form of Sempra Energy 2019 Long-Term Incentive Plan Non-Employee Directors’ Initial Restricted Stock Unit Award.
10-Q 10.4 08/02/19
10.44 Form of 2018 Sempra Energy Non-Employee Directors’ Initial Restricted Stock Unit Award.
10-K 10.50 02/27/18
10.45 Sempra Energy Amended and Restated Retirement Plan for Directors.
10-Q 10.7 08/07/08
10.46 Sempra Energy Annual Incentive Plan.
10-Q 10.7 05/07/18
10.47 Amended and Restated Severance Pay Agreement between Sempra Energy and Jeffrey W. Martin, dated May 1, 2018.
10-Q 10.3 08/06/18
10.48 Amended and Restated Severance Pay Agreement between Sempra Energy and Kevin C. Sagara, signed October 3, 2020 and effective as of June 27, 2020.
10-Q 10.2 11/05/20
10.49 Amended and Restated Severance Pay Agreement between Sempra Energy and Trevor I. Mihalik, dated May 1, 2018.
10-Q 10.5 08/06/18
10.50 Amended and Restated Severance Pay Agreement between Sempra Energy and Peter R. Wall signed October 3, 2020 and effective as of July 1, 2020.
10-Q 10.3 11/05/20
10.51 Amended and Restated Severance Pay Agreement between Sempra Energy and Karen L. Sedgwick, dated December 20, 2021.
X
EXHIBIT INDEX (CONTINUED)
Incorporated by Reference
Exhibit Number Exhibit Description Filed or Furnished Herewith Form or Registration Statement No. Exhibit or Appendix Filing Date
Sempra Energy / San Diego Gas & Electric Company
10.52 Form of San Diego Gas & Electric Company Executive Incentive Compensation Plan.
10-K 10.64 02/27/14
10.53 Severance Pay Agreement between Sempra Energy and Caroline A. Winn, signed May 7, 2020 and effective as of January 1, 2020.
10-Q 10.1 08/05/20
10.54 Severance Pay Agreement between Sempra Energy and Bruce A. Folkmann, dated March 1, 2017.
10-Q 10.15 05/09/17
10.55 Severance Pay Agreement between Sempra Energy and Valerie A. Bille, signed September 30, 2020 and effective as of August 22, 2020.
10-Q 10.4 11/05/20
10.56 Severance Pay Agreement between Sempra Energy and Diana L. Day dated March 1, 2017.
10-K 10.68 02/26/19
Sempra Energy / Southern California Gas Company
10.57 Form of Southern California Gas Company Executive Incentive Compensation Plan.
10-K 10.71 02/27/14
10.58 Severance Pay Agreement between Sempra Energy and Scott D. Drury dated August 25, 2018.
10-Q 10.4 11/07/18
10.59 Severance Pay Agreement between Sempra Energy and Maryam S. Brown, dated March 1, 2017.
10-Q 10.7 08/02/19
10.60 Severance Pay Agreement between Sempra Energy and Jimmie I. Cho, signed May 4, 2020, effective as of January 1, 2020.
10-Q 10.2 08/05/20
10.61 Severance Pay Agreement between Sempra Energy and Mia DeMontigny, dated June 15, 2019.
10-Q 10.6 08/02/19
10.62 Severance Pay Agreement between Sempra Energy and David J. Barrett, dated January 12, 2019.
10-K 10.77 02/26/19
10.63 Severance Pay Agreement between Sempra Energy and Jeffery L. Walker, dated March 16, 2019.
10-K 10.67 02/25/21
EXHIBIT 14 -- CODE OF ETHICS
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
14.1 Sempra Energy Code of Business Conduct and Ethics for Directors and Principal and Executive Officers (also applies to Principal Officers of San Diego Gas & Electric Company and Southern California Gas Company).
X
EXHIBIT INDEX (CONTINUED)
Exhibit Number Exhibit Description Filed or Furnished Herewith
EXHIBIT 21 -- SUBSIDIARIES
Sempra Energy
21.1 Sempra Energy Schedule of Certain Subsidiaries at December 31, 2021.
X
EXHIBIT 23 -- CONSENTS OF EXPERTS AND COUNSEL
Sempra Energy
23.1 Sempra Energy Consent of Independent Registered Public Accounting Firm.
X
23.2 Oncor Electric Delivery Holdings Company LLC Consent of Independent Auditors.
X
San Diego Gas & Electric Company
23.3 San Diego Gas & Electric Company Consent of Independent Registered Public Accounting Firm.
X
Southern California Gas Company
23.4 Southern California Gas Company Consent of Independent Registered Public Accounting Firm.
X
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1 Certification of Sempra Energy’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
31.2 Certification of Sempra Energy’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
San Diego Gas & Electric Company
31.3 Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
31.4 Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
Southern California Gas Company
31.5 Certification of Southern California Gas Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
31.6 Certification of Southern California Gas Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1 Certification of Sempra Energy’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
X
32.2 Certification of Sempra Energy’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
X
San Diego Gas & Electric Company
32.3 Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
X
32.4 Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
X
EXHIBIT INDEX (CONTINUED)
Exhibit Number Exhibit Description Filed or Furnished Herewith
Southern California Gas Company
32.5 Certification of Southern California Gas Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
X
32.6 Certification of Southern California Gas Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
X
EXHIBIT 99 -- ADDITIONAL EXHIBITS
Sempra Energy
99.1 Audited consolidated financial statements of Oncor Electric Delivery Holdings Company LLC and subsidiary as of December 31, 2021, 2020 and 2019 and for each of the three years ended in the period ended December 31, 2021, and the related Independent Auditors’ Report.
X
EXHIBIT 101 -- INTERACTIVE DATA FILE
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document. X
101.SCH XBRL Taxonomy Extension Schema Document. X
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document. X
101.DEF XBRL Taxonomy Extension Definition Linkbase Document. X
101.LAB XBRL Taxonomy Extension Label Linkbase Document. X
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document. X
EXHIBIT 104 -- COVER PAGE
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).