Company: SEMPRA ENERGY
CIK: 1032208
SIC: 4931
Filing Date: 2022-02-25 00:00:00

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:
(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:
(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
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.

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

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.

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.”

ITEM 4 - RESERVED
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II.

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:
(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.

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

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
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.
(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.
(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.
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.
(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.
(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
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:
(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:
(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.

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.

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

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

ITEM 9B - OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III.
Because SDG&E meets the conditions of General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this report with a reduced disclosure format as permitted by General Instruction I(2), the information required by Part III - Items 10, 11, 12 and 13 below is not required for SDG&E. We have, however, voluntarily provided the information required by Item 401 of SEC Regulation S-K, as required by Part III -

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS
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.

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.

ITEM 12 - SECURITY OWNERSHIP
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.
(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.

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.

ITEM 14 - PRINCIPAL ACCOUNTANT 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.
(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.

ITEM 15 - EXHIBITS AND 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).
(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.
(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.
* 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.
ITEM 16. FORM 10-K SUMMARY
Not applicable.
Sempra Energy:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SEMPRA ENERGY,
(Registrant)
By: /s/ J. Walker Martin
J. Walker Martin
Chairman, Chief Executive Officer and President
Date: February 25, 2022
Pursuant to the requirements of the Securities Exchange Act of 1934 (the Act), this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Name/Title Signature Date
Principal Executive Officer:
J. Walker Martin
Chief Executive Officer and President
/s/ J. Walker Martin February 25, 2022
Principal Financial Officer:
Trevor I. Mihalik
Executive Vice President and Chief Financial Officer
/s/ Trevor I. Mihalik February 25, 2022
Principal Accounting Officer:
Peter R. Wall
Senior Vice President, Controller and Chief Accounting Officer
/s/ Peter R. Wall February 25, 2022
Directors:
J. Walker Martin, Chairman /s/ J. Walker Martin February 25, 2022
Alan L. Boeckmann, Director /s/ Alan L. Boeckmann February 25, 2022
Andrés Conesa, Director /s/ Andrés Conesa February 25, 2022
Maria Contreras-Sweet, Director /s/ Maria Contreras-Sweet February 25, 2022
Pablo A. Ferrero, Director /s/ Pablo A. Ferrero February 25, 2022
William D. Jones, Director /s/ William D. Jones February 25, 2022
Bethany J. Mayer, Director /s/ Bethany J. Mayer February 25, 2022
Michael N. Mears, Director /s/ Michael N. Mears February 25, 2022
Jack T. Taylor, Director /s/ Jack T. Taylor February 25, 2022
Cynthia L. Walker, Director /s/ Cynthia L. Walker February 25, 2022
Cynthia J. Warner, Director /s/ Cynthia J. Warner February 25, 2022
James C. Yardley, Director /s/ James C. Yardley February 25, 2022
San Diego Gas & Electric Company:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SAN DIEGO GAS & ELECTRIC COMPANY,
(Registrant)
By: /s/ Caroline A. Winn
Caroline A. Winn
Chief Executive Officer
Date: February 25, 2022
Pursuant to the requirements of the Securities Exchange Act of 1934 (the Act), this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Name/Title Signature Date
Principal Executive Officer:
Caroline A. Winn
Chief Executive Officer
/s/ Caroline A. Winn February 25, 2022
Principal Financial Officer:
Bruce A. Folkmann
President and Chief Financial Officer
/s/ Bruce A. Folkmann February 25, 2022
Principal Accounting Officer:
Valerie A. Bille
Vice President, Controller and Chief Accounting Officer
/s/ Valerie A. Bille February 25, 2022
Directors:
Kevin C. Sagara, Non-Executive Chairman /s/ Kevin C. Sagara February 25, 2022
Robert J. Borthwick, Director /s/ Robert J. Borthwick February 25, 2022
Erbin B. Keith, Director /s/ Erbin B. Keith February 25, 2022
Caroline A. Winn, Director /s/ Caroline A. Winn February 25, 2022
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT:
No annual report, proxy statement, form of proxy or other soliciting material has been sent to security holders during the period covered by this annual report on Form 10-K, and no such materials are to be furnished to security holders subsequent to the filing of this annual report on Form 10-K.
Southern California Gas Company:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA GAS COMPANY,
(Registrant)
By: /s/ Scott D. Drury
Scott D. Drury
Chief Executive Officer
Date: February 25, 2022
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Name/Title Signature Date
Principal Executive Officer:
Scott D. Drury
Chief Executive Officer
/s/ Scott D. Drury February 25, 2022
Principal Financial and Accounting Officer:
Mia L. DeMontigny
Chief Financial Officer, Controller and Chief Accounting Officer
/s/ Mia L. DeMontigny February 25, 2022
Directors:
Kevin C. Sagara, Non-Executive Chairman /s/ Kevin C. Sagara February 25, 2022
Scott D. Drury, Director /s/ Scott D. Drury February 25, 2022
Lisa Larroque Alexander, Director /s/ Lisa Larroque Alexander February 25, 2022
Karen L. Sedgwick, Director /s/ Karen L. Sedgwick February 25, 2022
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm (PCAOB ID 34)
Consolidated Financial Statements: Sempra San Diego
Gas & Electric Company
Southern California Gas Company
Consolidated Statements of Operations for the years ended December 31, 2021, 2020 and 2019
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019
Consolidated Balance Sheets at December 31, 2021, 2020 and 2019
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019
Consolidated Statements of Changes in Equity for the years ended December 31, 2021, 2020 and 2019
N/A
Statements of Changes in Shareholders’ Equity for the years ended December 31, 2021, 2020 and 2019 N/A N/A
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies and Other Financial Data
Note 2. New Accounting Standards
Note 3. Revenues
Note 4. Regulatory Matters
Note 5. Acquisitions, Divestitures and Discontinued Operations
Note 6. Investments in Unconsolidated Entities
Note 7. Debt and Credit Facilities
Note 8. Income Taxes
Note 9. Employee Benefit Plans
Note 10. Share-Based Compensation
Note 11. Derivative Financial Instruments
Note 12. Fair Value Measurements
Note 13. Preferred Stock
Note 14. Sempra - Shareholders’ Equity and Earnings Per Common Share
Note 15. San Onofre Nuclear Generating Station
Note 16. Commitments and Contingencies
Note 17. Segment Information
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Sempra Energy:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Sempra Energy and subsidiaries (“Sempra”) as of December 31, 2021, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2021, the related notes, and the schedule listed in Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sempra as of December 31, 2021, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), Sempra’s internal control over financial reporting 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, and our report dated February 25, 2022 expressed an unqualified opinion on Sempra’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of Sempra’s management. Our responsibility is to express an opinion on Sempra’s financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Insurance Receivable Related to Aliso Canyon Gas Leak - Refer to Note 16 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
Sempra has an insurance receivable of $360 million as of December 31, 2021 related to certain costs arising from the Aliso Canyon natural gas storage facility gas leak. Sempra has determined that the insurance receivable is probable of recovery based on the nature of the insurance claims, the costs incurred, and the coverage provided by applicable insurance policies.
We identified the recoverability of the insurance receivable as a critical audit matter due to the management judgments required in assessing if, and to what degree, the coverage provided by applicable insurance policies would cover the types of costs included in the insurance claims submitted. Auditing the probability of recovery of the insurance receivable required subjective auditor judgment and extensive audit effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the probability of recovery of the insurance receivable for the costs related to the Aliso Canyon natural gas storage facility gas leak included the following, among others:
▪We tested the effectiveness of management’s internal controls over the costs included in the related insurance receivable and the evaluation of the recoverability of this insurance receivable.
▪With the assistance of an insurance specialist, we evaluated management’s judgments related to the determination of the recoverability of the insurance receivable by:
◦Evaluating the coverage provided by applicable insurance policies and evaluating the potential coverage available under such policies based on the nature of the underlying costs.
◦Evaluating the probability of recovery of the insurance receivable by obtaining correspondence between Sempra and the applicable insurers.
◦Evaluating the probability of recovery of the insurance receivable through inquiries with management and with external legal counsel of Sempra and we evaluated whether the information provided was consistent with our other procedures.
◦Searching external sources for and considering any contradictory evidence to Sempra’s accounting assessment of probability of recoverability of the insurance receivable.
▪We evaluated whether Sempra’s disclosures were appropriate and consistent with the information obtained in our procedures.
Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 1 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
Sempra is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We read relevant regulatory orders issued by the Commissions for Sempra and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
▪We evaluated Sempra’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 25, 2022
We have served as Sempra’s auditor since 1935.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholder and Board of Directors of San Diego Gas & Electric Company:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of San Diego Gas & Electric Company (“SDG&E”) as of December 31, 2021, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of SDG&E as of December 31, 2021, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SDG&E’s internal control over financial reporting 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, and our report dated February 25, 2022 expressed an unqualified opinion on SDG&E’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of SDG&E’s management. Our responsibility is to express an opinion on SDG&E’s financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 1 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
SDG&E is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We read relevant regulatory orders issued by the Commissions for SDG&E and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
▪We evaluated SDG&E’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 25, 2022
We have served as SDG&E’s auditor since 1935.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Southern California Gas Company:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Southern California Gas Company (“SoCalGas”) as of December 31, 2021, 2020 and 2019, the related statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of SoCalGas as of December 31, 2021, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SoCalGas’ internal control over financial reporting 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, and our report dated February 25, 2022 expressed an unqualified opinion on SoCalGas’ internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of SoCalGas’ management. Our responsibility is to express an opinion on SoCalGas’ financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Insurance Receivable Related to Aliso Canyon Gas Leak - Refer to Note 16 of the Notes to Financial Statements
Critical Audit Matter Description
SoCalGas has an insurance receivable of $360 million as of December 31, 2021 related to certain costs arising from the Aliso Canyon natural gas storage facility gas leak. SoCalGas has determined that the insurance receivable is probable of recovery based on the nature of the insurance claims, the costs incurred, and the coverage provided by applicable insurance policies.
We identified the recoverability of the insurance receivable as a critical audit matter due to the management judgments required in assessing if, and to what degree, the coverage provided by applicable insurance policies would cover the types of costs included in the insurance claims submitted. Auditing the probability of recovery of the insurance receivable required subjective auditor judgment and extensive audit effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the probability of recovery of the insurance receivable for the costs related to the Aliso Canyon natural gas storage facility gas leak included the following, among others:
▪We tested the effectiveness of management’s internal controls over the costs included in the related insurance receivable and the evaluation of the recoverability of this insurance receivable.
▪With the assistance of an insurance specialist, we evaluated management’s judgments related to the determination of the recoverability of the insurance receivable by:
◦Evaluating the coverage provided by applicable insurance policies and evaluating the potential coverage available under such policies based on the nature of the underlying costs.
◦Evaluating the probability of recovery of the insurance receivable by obtaining correspondence between SoCalGas and the applicable insurers.
◦Evaluating the probability of recovery of the insurance receivable through inquiries with management and with external legal counsel of SoCalGas and we evaluated whether the information provided was consistent with our other procedures.
◦Searching external sources for and considering any contradictory evidence to SoCalGas’ accounting assessment of probability of recoverability of the insurance receivable.
▪We evaluated whether SoCalGas’ disclosures were appropriate and consistent with the information obtained in our procedures.
Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 1 of the Notes to Financial Statements
Critical Audit Matter Description
SoCalGas is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We read relevant regulatory orders issued by the Commissions for SoCalGas and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
▪We evaluated SoCalGas’ disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 25, 2022
We have served as SoCalGas’ auditor since 1937.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements.
See Notes to Financial Statements.
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See Notes to Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA
PRINCIPLES OF CONSOLIDATION
Sempra
Sempra’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based holding company doing business as Sempra, and its consolidated entities. 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 discussions of our reportable segments reflect the revised segment information of our four separate reportable segments, which we discuss in Note 17. All references in these Notes to our reportable segments are not intended to refer to any legal entity with the same or similar name.
SDG&E
SDG&E’s Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E was the primary beneficiary until August 23, 2019, at which time SDG&E deconsolidated the VIE, as we discuss below in “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra.
SoCalGas
SoCalGas’ common stock is wholly owned by PE, which is a wholly owned subsidiary of Sempra.
BASIS OF PRESENTATION
This is a combined report of Sempra, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our,” “us” and “Sempra” are to Sempra and its consolidated entities, collectively, unless otherwise stated or indicated by the context. We sometimes refer to SDG&E and SoCalGas collectively as Sempra California. SI Partners (formerly Sempra Global) is the holding company for our subsidiaries that are not subject to California or Texas utility regulation. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.
Throughout these Notes, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:
▪the Consolidated Financial Statements and related Notes of Sempra;
▪the Consolidated Financial Statements and related Notes of SDG&E; and
▪the Financial Statements and related Notes of SoCalGas.
Use of Estimates in the Preparation of the Financial Statements
We have prepared our Consolidated Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.
Discontinued Operations
We completed the sales of our equity interests in our Peruvian businesses in April 2020 and our Chilean businesses in June 2020. We determined that these businesses, which previously constituted the Sempra South American Utilities segment, and certain activities associated with these businesses, met the held-for-sale criteria upon our decision to sell them in January 2019. These
businesses are presented as discontinued operations, which we discuss further in Note 5. Our discussions in the Notes below relate only to our continuing operations unless otherwise noted.
Subsequent Events
We evaluated events and transactions that occurred after December 31, 2021 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments and disclosures necessary for a fair presentation.
REGULATED OPERATIONS
SDG&E’s and SoCalGas’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, SDG&E and SoCalGas record regulatory liabilities when the CPUC or, in the case of SDG&E, the FERC, requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.
Determining probability of recovery of regulatory assets requires judgment by management and may include, but is not limited to, consideration of:
▪the nature of the event giving rise to the assessment
▪existing statutes and regulatory code
▪legal precedents
▪regulatory principles and analogous regulatory actions
▪testimony presented in regulatory hearings
▪regulatory orders
▪a commission-authorized mechanism established for the accumulation of costs
▪status of applications for rehearings or state court appeals
▪specific approval from a commission
▪historical experience
Sempra Infrastructure’s natural gas distribution utility, Ecogas, also applies U.S. GAAP for rate-regulated utilities to its operations, including the same evaluation of probability of recovery of regulatory assets described above.
Our Sempra Texas Utilities segment is comprised of our equity method investments in Oncor Holdings, which owns an 80.25% interest in Oncor, and Sharyland Holdings, which owns 100% of Sharyland Utilities. Oncor and Sharyland Utilities are regulated electric transmission and distribution utilities in Texas and their rates are regulated by the PUCT and certain cities and are subject to regulatory rate-setting processes and earnings oversight. Oncor and Sharyland Utilities prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.
Our Sempra Infrastructure segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. Certain business activities at IEnova are regulated by the CRE and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction at IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of AFUDC related to equity. We discuss AFUDC below in “Property, Plant and Equipment.”
FAIR VALUE MEASUREMENTS
We measure certain assets and liabilities at fair value on a recurring basis, primarily NDT and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances.
A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.
We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 - Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, short-term investments, and U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:
▪quoted forward prices for commodities
▪time value
▪current market and contractual prices for the underlying instruments
▪volatility factors
▪other relevant economic measures
Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options.
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions at SDG&E and the Support Agreement at Sempra Infrastructure.
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.
Restricted cash includes:
▪for Sempra Infrastructure, funds denominated in Mexican pesos to pay for rights-of-way, license fees, permits, topographic surveys and other costs pursuant to trust and debt agreements related to pipeline projects
▪for Parent and other, funds held in a delisting trust for the purpose of purchasing the remaining publicly owned IEnova shares
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on Sempra’s Consolidated Balance Sheets to the sum of such amounts reported on Sempra’s Consolidated Statements of Cash Flows.
In Sempra’s Consolidated Statement of Cash Flows for the year ended December 31, 2020, the ending cash, cash equivalents and restricted cash balance in discontinued operations of $4.6 billion is considered to be cash, cash equivalents and restricted cash for continuing operations following the sales of the South American businesses.
CREDIT LOSSES
We are exposed to credit losses from financial assets measured at amortized cost, including trade and other accounts receivable, amounts due from unconsolidated affiliates, our net investment in a sales-type lease and a note receivable. We are also exposed to credit losses from off-balance sheet arrangements through Sempra’s guarantee related to Cameron LNG JV’s SDSRA, which we discuss in Note 6.
We regularly monitor and evaluate credit losses and record allowances for expected credit losses, if necessary, for trade and other accounts receivable using a combination of factors, including past-due status based on contractual terms, trends in write-offs, the age of the receivables and customer payment patterns, historical and industry trends, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies, pandemics and other factors. We write off financial assets measured at amortized cost in the period in which we determine they are not recoverable. We record recoveries of amounts previously written off when it is known that they will be recovered.
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.
As we discuss in Note 4, the CPUC authorized SDG&E and SoCalGas to track and request recovery of incremental costs, including uncollectible expenses, associated with complying with customer protection measures ordered by the CPUC related to the COVID-19 pandemic.
In connection with a separate CPUC decision addressing residential service disconnections, SDG&E and SoCalGas each established a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding utility bill amounts provided under the AMP, as we discuss in Note 4.
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.
We provide below allowances and changes in allowances for credit losses for trade receivables and other receivables. SDG&E and SoCalGas record changes in the allowances for credit losses related to Accounts Receivable - Trade in regulatory accounts.
Allowances for credit losses are included in the Consolidated Balance Sheets as follows:
As we discuss below in “Transactions with Affiliates,” we have loans due from unconsolidated affiliates with varying tenors, interest rates and currencies. On a quarterly basis, we evaluate credit losses and record allowances for expected credit losses on amounts due from unconsolidated affiliates, if necessary, based on credit quality indicators such as external credit ratings, published default rate studies, the maturity date of the instrument and past delinquencies. However, we do not record allowances for expected credit losses related to accrued interest receivable on loans due from unconsolidated affiliates because we write off such amounts, if any, through a reversal of interest income in the period we determine such amounts are uncollectible. In the absence of external credit ratings, we may utilize an internally developed credit rating based on our analysis of a counterparty’s financial statements to determine our expected credit losses. At December 31, 2021 and 2020, $1 million and $3 million, respectively, of expected credit losses are included in noncurrent Due From Unconsolidated Affiliates on Sempra’s Consolidated Balance Sheets.
As we discuss below in “Note Receivable,” Sempra loaned $300 million to KKR in exchange for an interest-bearing promissory note. We evaluate credit losses and record allowances for expected credit losses on this note receivable based on published default rate studies, the maturity date of the instrument and an internally developed credit rating. At December 31, 2021, $8 million of expected credit losses is included in Other Long-Term Assets on Sempra’s Consolidated Balance Sheet.
As we discuss below in Note 6, Sempra provided a guarantee for the benefit of Cameron LNG JV related to amounts withdrawn by Sempra Infrastructure from the SDSRA. At December 31, 2021, expected credit losses of $7 million related to this guarantee are included in Deferred Credits and Other on Sempra’s Consolidated Balance Sheet.
CONCENTRATION OF CREDIT RISK
Credit risk is the risk of loss that would be incurred as a result of nonperformance by our counterparties on their contractual obligations. We have policies governing the management of credit risk that are administered by the respective credit departments at each of our segments and overseen by their separate risk management committees.
This oversight includes calculating current and potential credit risk on a regular basis and monitoring actual balances in comparison to approved limits. We establish credit limits based on risk and return considerations under terms customarily available in the industry. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of:
▪prospective counterparties’ financial condition (including credit ratings)
▪collateral requirements
▪the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty
▪downgrade triggers
We believe that we have provided adequate reserves for counterparty nonperformance in our allowances for credit losses.
When our development projects become operational, we rely significantly on the ability of suppliers to perform under long-term agreements and on our ability to enforce contract terms in the event of nonperformance. Also, the factors that we consider in evaluating a development project include negotiating customer and supplier agreements and, therefore, we rely on these agreements for future performance. We also may condition our decision to go forward on development projects on first obtaining these customer and supplier agreements.
INVENTORIES
SDG&E and SoCalGas value natural gas inventory using the last-in first-out method. As inventories are sold, differences between the last-in first-out valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. SDG&E and SoCalGas generally value materials and supplies at the lower of average cost or net realizable value.
Sempra Infrastructure values natural gas inventory and materials and supplies at the lower of average cost or net realizable value, and LNG inventory using the first-in first-out method.
The components of inventories are as follows:
NOTE RECEIVABLE
In connection with the KKR Purchase Agreement, which we define and discuss below in “Noncontrolling Interests,” we entered into an accommodation and support agreement under which KKR issued a $300 million interest bearing promissory note to Sempra in exchange for cash. Loan-related transaction costs incurred by KKR totaled $5 million, which were reimbursed by Sempra per the terms of the agreement. The promissory note is due to be repaid in full no later than October 1, 2029 and bears compound interest at 5% per annum, which may be paid quarterly or added to the outstanding principal at the election of KKR. At December 31, 2021, Other Long-Term Assets includes $297 million of outstanding principal, net of allowance for credit losses, and Other Current Assets includes $3 million of interest receivable on Sempra’s Consolidated Balance Sheet.
WILDFIRE FUND
In July 2019, the Wildfire Legislation was signed into law. The Wildfire Legislation addresses certain issues related to catastrophic wildfires in the State of California and their impact on electric IOUs. Investor-owned gas distribution utilities such as SoCalGas are not covered by this legislation. The issues addressed include wildfire mitigation, cost recovery standards and requirements, a wildfire fund, a cap on liability, and the establishment of a wildfire safety board.
The Wildfire Legislation provided that SDG&E would not recover the ROE on its first $215 million of fire risk mitigation capital expenditures.
The Wildfire Legislation established a revised legal standard for the recovery of wildfire costs (Revised Prudent Manager Standard) and established a fund (the Wildfire Fund) designed to provide liquidity to SDG&E, PG&E and Edison to pay IOU wildfire-related claims in the event that the governmental agency responsible for determining causation determines the applicable IOU’s equipment caused the ignition of a wildfire, primary insurance coverage is exceeded and certain other conditions are satisfied. A primary purpose of the Wildfire Fund is to pool resources provided by shareholders and ratepayers of the IOUs and make those resources available to reimburse the IOUs for third-party wildfire claims incurred after July 12, 2019, the effective date of the Wildfire Legislation, subject to certain limitations.
An IOU may seek payment from the Wildfire Fund for settled or adjudicated third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $1 billion or the IOU’s required amount of insurance coverage as recommended by the Wildfire Fund’s administrator. Wildfire claims approved by the Wildfire Fund’s administrator will be paid by the Wildfire Fund to the IOU to the extent funds are available. These utilized funds will be subject to review by the CPUC, which will make a determination as to the degree an IOU’s conduct related to an ignition of a wildfire was prudent or imprudent. The Revised Prudent Manager Standard requires that the CPUC apply clear standards when reviewing wildfire liability losses paid when determining the reasonableness of an IOU’s conduct related to an ignition. Under this standard, the conduct under review related to the ignition may include factors within and beyond the IOU’s control, including humidity, temperature and winds. Costs and expenses may be allocated for cost recovery in full or in part. Also, under this standard, an IOU’s conduct will be deemed reasonable if a valid annual safety certification is in place at the time of the ignition, unless a serious doubt is raised, in which case the burden shifts to the utility to dispel that doubt. The IOUs will receive an annual safety certification from the CPUC if they meet various requirements.
If an IOU has maintained a valid annual safety certification, to the extent it is found to be imprudent, claims will be reimbursable by the IOU to the Wildfire Fund up to a cap based on the IOU’s rate base. The aggregate requirement to reimburse the Wildfire Fund over a trailing three calendar year period is capped at 20% of the equity portion of an IOU’s electric transmission and distribution rate base in the year of the prudency determination. Based on its 2021 rate base, the liability cap for SDG&E is approximately $1.1 billion, which is adjusted annually. The liability cap will apply on a rolling three-year basis so long as future annual safety certifications are received and the Wildfire Fund has not been terminated, which could occur if funds are exhausted. Amounts in excess of the liability cap and amounts that are determined to be prudently incurred do not need to be reimbursed by an IOU to the Wildfire Fund. The Wildfire Fund does not have a specified term and coverage will continue until the assets of the Wildfire Fund are exhausted and the Wildfire Fund is terminated, in which case, the remaining funds, if any, will be transferred to California’s general fund to be used for fire risk mitigation programs.
In July 2021, the CPUC approved SDG&E’s 2021 Wildfire Mitigation Plan. In July 2021, the CPUC’s Wildfire Safety Division became the OEIS under the California Natural Resources Agency. As successor to the Wildfire Safety Division, the OEIS maintains the duties and responsibilities of the former Wildfire Safety Division with respect to Wildfire Mitigation Plans. The 2021 Wildfire Mitigation Plan is effective until the OEIS approves a new plan. In December 2021, SDG&E received its 2021 wildfire safety certification from the OEIS, which is valid for 12 months from the issue date.
The Wildfire Fund was initially funded up to $10.5 billion by a loan from the State of California Surplus Money Investment Fund. The loan is financed through a DWR bond, which was put in place on October 1, 2020 and is securitized through a dedicated surcharge on ratepayers’ bills attributable to the DWR. In October 2019, the CPUC adopted a decision authorizing a non-bypassable charge to be collected by the IOUs to support the anticipated DWR bond issuance authorized by AB 1054. The CPUC decision also determined that ratepayers of non-participating electrical corporations shall not pay the non-bypassable charge.
The Wildfire Fund was also funded by initial shareholder contributions from the IOUs totaling $7.5 billion. SDG&E’s share was $322.5 million. The IOUs are also required to make annual shareholder contributions to the Wildfire Fund with an aggregate value of $3 billion over a 10-year period starting in 2019. SDG&E’s share is $129 million. The contributions are not subject to rate recovery.
In a complaint filed in U.S. District Court for the Northern District of California in July 2019, plaintiffs seek to invalidate AB 1054 based on allegations that the legislation violates federal law. The district court and, subsequently, the U.S. Court of Appeals for the Ninth Circuit dismissed the complaint.
Wildfire Fund Asset and Obligation
In 2019, SDG&E recorded both a Wildfire Fund asset and a related obligation for its commitment to make shareholder contributions of $451.5 million to the Wildfire Fund, measured at present value as of July 25, 2019 (the date by which both Edison and SDG&E opted to contribute to the Wildfire Fund). SDG&E paid its initial shareholder contribution of $322.5 million to the Wildfire Fund in September 2019. SDG&E funded this contribution with proceeds from an equity contribution from Sempra. SDG&E expects to continue to make annual shareholder contributions of $12.9 million through December 31, 2028. SDG&E accretes the present value of the Wildfire Fund obligation until the liability is settled.
SDG&E is amortizing the Wildfire Fund asset on a straight-line basis over the estimated period of benefit, as adjusted for utilization by the IOUs. The estimated period of benefit of the Wildfire Fund asset is 15 years and is based on several assumptions, including, but not limited to:
▪historical wildfire experience of each IOU in the State of California, including frequency and severity of the wildfires
▪the value of property potentially damaged by wildfires
▪the effectiveness of wildfire risk mitigation efforts by each IOU
▪liability cap of each IOU
▪IOU prudency determination levels
▪FERC jurisdictional allocation levels
▪insurance coverage levels
The use of different assumptions, or changes to the assumptions used, could have a significant impact on the estimated period of benefit of the Wildfire Fund asset. SDG&E periodically evaluates the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in these assumptions. SDG&E recognizes a reduction of its Wildfire Fund asset and records a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, decrease the Wildfire Fund asset and remaining available coverage.
The following table summarizes the location of balances related to the Wildfire Fund on Sempra’s and SDG&E’s Consolidated Balance Sheets and Consolidated Statements of Operations.
(1) Included in O&M for SDG&E.
INCOME TAXES
Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. Investment tax credits from prior years are amortized to income by SDG&E and SoCalGas over the estimated service lives of the properties as required by the CPUC.
Under the regulatory accounting treatment required for flow-through temporary differences, SDG&E, SoCalGas and Sempra Infrastructure recognize:
▪regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and
▪regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned to customers.
When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.
Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.
We accrue income tax to the extent we intend to repatriate cash to the U.S. from our continuing international operations. We currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries because they are indefinitely reinvested. We recognize income tax expense for basis differences related to global intangible low-taxed income as a period cost if and when incurred.
We provide additional information about income taxes in Note 8.
GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS
SDG&E, SoCalGas and Sempra Infrastructure are required by AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. At SDG&E and SoCalGas, many GHG allowances are allocated to us on behalf of our customers at no cost. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Infrastructure records the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.
RENEWABLE ENERGY CERTIFICATES
RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.
Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS Program established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS Program. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.
PROPERTY, PLANT AND EQUIPMENT
PP&E is recorded at cost and primarily represents the buildings, equipment and other facilities used by SDG&E and SoCalGas to provide natural gas and electric utility services, and by the Sempra Infrastructure businesses in their operations, including construction work in progress. PP&E also includes lease improvements and other equipment at Parent and other. Our plant costs include labor, materials and contract services and expenditures for replacement parts incurred during a major maintenance outage of a plant. In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP includes AFUDC. The cost of PP&E for our non-regulated projects includes capitalized interest. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage value is charged to accumulated depreciation. We discuss assets collateralized as security for certain indebtedness in Note 7.
(1) At December 31, 2021, includes $542 in electric transmission assets and $5 in construction work in progress related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in Sempra’s and SDG&E’s Consolidated Statements of Operations.
(2) Includes $211, $191 and $178 at December 31, 2021, 2020, and 2019, respectively, of utility plant, primarily pipelines and other distribution assets at Ecogas.
(3) Estimated useful lives are for land rights.
Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period for SDG&E and SoCalGas, or the remaining term of the site leases, whichever is shortest.
(1) Includes $292 at December 31, 2021 related to SDG&E’s 86% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.
(2) Includes $55, $51 and $49 at December 31, 2021, 2020, and 2019, respectively, of accumulated depreciation for utility plant at Ecogas.
SDG&E and SoCalGas finance construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. SDG&E and SoCalGas earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.
Pipeline projects under construction by Sempra Infrastructure that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC.
We capitalize interest costs incurred to finance capital projects and interest at equity method investments that have not commenced planned principal operations.
The table below summarizes capitalized financing costs, comprised of AFUDC and capitalized interest.
GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized, but we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, we record a goodwill impairment loss as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.
For our annual goodwill impairment testing, we have the option to first make a qualitative assessment of whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, then we perform the quantitative goodwill impairment test. If, after performing the quantitative goodwill impairment test, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.
Goodwill of $1,602 million at December 31, 2021, 2020, and 2019 relates to the 2016 acquisitions of IEnova Pipelines and the Ventika wind power generation facilities at Sempra Infrastructure.
Other Intangible Assets
Other Intangible Assets included on Sempra’s Consolidated Balance Sheets are as follows:
Other Intangible Assets at December 31, 2021 primarily include:
▪renewable energy transmission and consumption permits previously granted by the CRE at the Ventika wind power generation facilities, Don Diego Solar and Border Solar;
▪a favorable O&M agreement acquired in connection with the acquisition of DEN; and
▪the relative fair value of the PPA that was acquired in connection with the acquisition of ESJ in March 2021.
Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for intangible assets was $22 million, including $10 million recorded against revenues, in 2021 and $11 million in both 2020 and 2019. We estimate amortization expense for the next five years to be $26 million per year, including $13 million per year recorded against revenues.
LONG-LIVED ASSETS
We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated entities. A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
VARIABLE INTEREST ENTITIES
We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based on qualitative and quantitative analyses, which assess:
▪the purpose and design of the VIE;
▪the nature of the VIE’s risks and the risks we absorb;
▪the power to direct activities that most significantly impact the economic performance of the VIE; and
▪the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.
We will continue to evaluate our VIEs for any changes that may impact our determination of whether an entity is a VIE and if we are the primary beneficiary.
SDG&E
SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs that include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and indirectly Sempra, is the primary beneficiary.
SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based on our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which it considers the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If SDG&E determines that it is the primary beneficiary, SDG&E and Sempra consolidate the entity that owns the facility as a VIE.
In addition to tolling agreements, other variable interests involve various elements of fuel and power costs, and other components of cash flows expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities, including the operation and maintenance activities of the generating facility, that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects could be significant to the financial position and liquidity of SDG&E and Sempra.
SDG&E determined that none of its PPAs and tolling agreements resulted in SDG&E being the primary beneficiary of a VIE at December 31, 2021, 2020 and 2019. PPAs and tolling agreements that relate to SDG&E’s involvement with VIEs are primarily accounted for as finance leases. The carrying amounts of the assets and liabilities under these contracts are included in PP&E, net, and finance lease liabilities with balances of $1,217 million, $1,237 million and $1,255 million at December 31, 2021, 2020 and 2019, respectively. SDG&E recovers costs incurred on PPAs, tolling agreements and other variable interests through CPUC-approved long-term power procurement plans. SDG&E has no residual interest in the respective entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 16. As a result, SDG&E’s potential exposure to loss from its variable interest in these VIEs is not significant.
Otay Mesa VIE
Through October 3, 2019, SDG&E had a tolling agreement to purchase power generated at OMEC, a 605-MW generating facility owned by OMEC LLC, which is a VIE that we refer to as Otay Mesa VIE. SDG&E determined that it was the primary beneficiary of Otay Mesa VIE, and therefore, SDG&E and Sempra consolidated Otay Mesa VIE. On August 23, 2019, SDG&E and OMEC LLC executed an amended resource adequacy capacity agreement that resulted in SDG&E and Sempra deconsolidating Otay Mesa VIE. No gain or loss was recognized upon deconsolidation.
Sempra Texas Utilities
Our 100% interest in Oncor Holdings is a VIE that owns an 80.25% interest in Oncor. Sempra is not the primary beneficiary of this VIE because of the structural and operational ring-fencing and governance measures in place that prevent us from having the
power to direct the significant activities of Oncor Holdings. As a result, we do not consolidate Oncor Holdings and instead account for our ownership interest as an equity method investment. See Note 6 for additional information about our equity method investment in Oncor Holdings and restrictions on our ability to influence its activities. Our maximum exposure to loss, which fluctuates over time, from our interest in Oncor Holdings does not exceed the carrying value of our investment, which was $12,947 million, $12,440 million and $11,519 million at December 31, 2021, 2020 and 2019, respectively.
Sempra Infrastructure
Cameron LNG JV
Cameron LNG JV is a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra is not the primary beneficiary of this VIE because we do not have the power to direct the most significant activities of Cameron LNG JV, including LNG production and operation and maintenance activities at the liquefaction facility. Therefore, we account for our investment in Cameron LNG JV under the equity method. The carrying value of our investment, including amounts recognized in AOCI related to interest-rate cash flow hedges at Cameron LNG JV, was $514 million at December 31, 2021, $433 million at December 31, 2020 and $1,256 million at December 31, 2019. Our maximum exposure to loss, which fluctuates over time, includes the carrying value of our investment and our obligation under the SDSRA, which we discuss in Note 6.
CFIN
As we discuss in Note 6, in July 2020, Sempra entered into a Support Agreement, which was amended in June 2021, for the benefit of CFIN, which is a VIE. Sempra is not the primary beneficiary of this VIE because we do not have the power to direct the most significant activities of CFIN, including modification, prepayment, and refinance decisions related to the financing arrangement with external lenders and Cameron LNG JV’s four project owners as well as the ability to determine and enforce remedies in the event of default. The conditional obligations of the Support Agreement represent a variable interest that we measure at fair value on a recurring basis (see Note 9). Sempra’s maximum exposure to loss under the terms of the Support Agreement is $979 million.
ECA LNG Phase 1
ECA LNG Phase 1 is a VIE because its total equity at risk is not sufficient to finance its activities without additional subordinated financial support. We expect that ECA LNG Phase 1 will require future capital contributions or other financial support to finance the construction of the facility. Sempra is the primary beneficiary of this VIE because we have the power to direct the development activities related to the construction of the liquefaction facility, which we consider to be the most significant activities of ECA LNG Phase 1 during the construction phase of its natural gas liquefaction export project. As a result, we consolidate ECA LNG Phase 1. Sempra Infrastructure consolidated $632 million and $207 million of assets at December 31, 2021 and 2020, respectively, consisting primarily of PP&E, net, and Accounts Receivable - Other attributable to ECA LNG Phase 1 that could be used only to settle obligations of this VIE and that are not available to settle obligations of Sempra, and $455 million and $49 million of liabilities at December 31, 2021 and 2020, respectively, consisting primarily of long-term debt, short-term debt and accounts payable attributable to ECA LNG Phase 1 for which creditors do not have recourse to the general credit of Sempra. Additionally, as we discuss in Note 7, Sempra and TotalEnergies SE have provided guarantees for the loan facility supporting construction of the liquefaction facility based on their respective proportionate ownership interest in ECA LNG Phase 1.
ASSET RETIREMENT OBLIGATIONS
For tangible long-lived assets, we record AROs for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record the estimated retirement cost using the present value of the obligation at the time the asset is placed into service, and recognize that cost over the life of the related asset by depreciating the asset retirement cost and accreting the obligation until the liability is settled. Our rate-regulated entities record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.
We have recorded AROs related to various assets, including:
SDG&E and SoCalGas
▪fuel and storage tanks
▪natural gas transmission and distribution systems
▪hazardous waste storage facilities
▪asbestos-containing construction materials
SDG&E
▪nuclear power facilities
▪electric transmission and distribution systems
▪energy storage systems
▪power generation plants
SoCalGas
▪underground natural gas storage facilities and wells
Sempra Infrastructure
▪natural gas transportation and distribution systems
▪power generation plants
▪LNG facility
▪LPG terminal
The changes in AROs are as follows:
(1) Current portion of the ARO for Sempra is included in Other Current Liabilities on the Consolidated Balance Sheets.
(2) SDG&E’s increase in ARO in 2021 includes $22 million due to a revised estimate related to the decommissioning of SONGS, which is offset in noncurrent Regulatory Assets.
CONTINGENCIES
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; and
▪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.
LEGAL FEES
Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred and amounts are estimable.
COMPREHENSIVE INCOME
Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:
▪foreign currency translation adjustments
▪certain hedging activities
▪changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans
The Consolidated Statements of Comprehensive Income (Loss) show the changes in the components of OCI, including the amounts attributable to NCI. The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to NCI.
(1) All amounts are net of income tax, if subject to tax, and exclude NCI.
(2) Includes discontinued operations in 2020 and 2019.
(3) Pension and Other Postretirement Benefits and Total AOCI include $6 in transfers of liabilities from SDG&E to SoCalGas and $3 in transfers of liabilities from SDG&E to Sempra in 2020 and $4 in transfers of liabilities from SoCalGas to Sempra in 2019 related to the nonqualified pension plans.
(4) Total AOCI includes $28 of foreign currency translation adjustments and $16 of financial instruments associated with the IEnova exchange and cash tender offers in 2021. Total AOCI includes $4 of foreign currency translation adjustments and $3 of financial instruments associated with IEnova’s repurchases of NCI in 2020. We discuss these transactions below in “Other Noncontrolling Interests - Sempra Infrastructure.” These transactions do not impact the Consolidated Statements of Comprehensive Income (Loss).
(5) Total AOCI includes $19 of foreign currency translation adjustments and $47 of financial instruments associated with the sale of NCI to KKR in 2021. We discuss this transaction below in “Other Noncontrolling Interests - Sempra Infrastructure.” This transaction does not impact the Consolidated Statements of Comprehensive Income (Loss).
(1) Amounts in 2019 include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
(2) Equity earnings at our foreign equity method investees are recognized after tax.
(3) Amounts are included in the computation of net periodic benefit cost (see “Net Periodic Benefit Cost” in Note 9).
NONCONTROLLING INTERESTS
Ownership interests in a consolidated entity that are held by unconsolidated owners are accounted for and reported as NCI.
SoCalGas Preferred Stock
The preferred stock at SoCalGas is presented at Sempra as NCI. Sempra records charges against income related to NCI for preferred dividends declared by SoCalGas. We provide additional information regarding SoCalGas’ preferred stock in Note 13.
Other Noncontrolling Interests
The following table provides information about NCI held by others in subsidiaries or entities consolidated by us and recorded in Other Noncontrolling Interests in Total Equity on Sempra’s Consolidated Balance Sheets.
(1) SI Partners and Chilquinta Energía have subsidiaries with NCI held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.
Sempra Infrastructure
Sale of NCI in SI Partners to KKR. On October 1, 2021, Sempra, its wholly owned subsidiary, SI Partners (formerly Sempra Global), and KKR consummated the transactions contemplated under a purchase and contribution agreement dated April 4, 2021 (as amended prior to closing, the KKR Purchase Agreement). Pursuant to the KKR Purchase Agreement, KKR acquired newly designated Class A Units representing a 20% NCI in SI Partners for a purchase price of $3.4 billion, including post-closing adjustments. As a result of this sale, we recorded a $1.3 billion increase in equity held by NCI and an increase in Sempra’s shareholders’ equity of $1.4 billion, net of $173 million in transaction costs and $490 million in tax impacts, including the tax effect of the sale and changes to a deferred income tax liability related to outside basis differences in SI Partners. Transaction costs include $149 million paid to KKR for reimbursement of certain expenses that KKR incurred in connection with closing the transaction.
Prior to the closing of the transactions contemplated under the KKR Purchase Agreement on October 1, 2021, we completed an internal legal reorganization to consolidate the assets of Sempra LNG Holding, LP and our ownership of IEnova under Sempra Global, which was renamed SI Partners. At closing, we owned 99.9% of the outstanding shares of IEnova. To the extent we later acquire additional shares of IEnova after the closing, such additional shares will be acquired by SI Partners and KKR will provide 20% of the funding.
Pursuant to the KKR Purchase Agreement, we have agreed to indemnify SI Partners for, among other things, certain losses arising from liabilities of SI Partners and its subsidiaries to the extent not primarily relating to the undertaking of the business of SI Partners, and we have agreed to indemnify KKR for losses attributable to pre-closing taxes.
At the closing of the sale of NCI in SI Partners to KKR, Sempra and KKR entered into a limited partnership agreement (the LP Agreement), which governs our and their respective rights and obligations in respect of our ownership interests in SI Partners. We maintain control of SI Partners as the 80% owner with KKR having certain minority protections commensurate with the size of its investment.
SI Partners has two authorized classes of units, designated as “Class A Units” (which are common voting units) and “Sole Risk Interests.” If KKR approves our request that a project not be pursued jointly, or if KKR decides not to participate in any proposed
project for which we nevertheless desire to make a positive final investment decision, we may proceed with such project either independently through a different investment vehicle or as a “Sole Risk Project” within SI Partners and receive Sole Risk Interests in respect thereof. Sole Risk Projects are separated from other SI Partners projects and are conducted at our sole cost, expense and liability and we receive, through the acquisition of Sole Risk Interests, any economic and other benefits from such projects. KKR is not entitled to any benefits or rights in respect of any Sole Risk Project. The Guaymas-El Oro segment of the Sonora pipeline currently constitutes a Sole Risk Project. Until a specified date, KKR has certain discretionary rights to cause the Guaymas-El Oro segment of the Sonora pipeline to cease to be a Sole Risk Project and be pursued jointly within SI Partners.
Under the LP Agreement, SI Partners is managed by a board of managers comprised of members designated by us and by KKR. Matters are generally decided by majority vote. The managers designated by us and the managers designated by KKR each, as a group, have voting power equivalent to the ownership percentage of their respective designating member. However, SI Partners and its controlled subsidiaries are prohibited from taking certain actions without the prior written approval of KKR (subject to KKR maintaining certain ownership thresholds in SI Partners).
The LP Agreement contains certain default remedies if we or KKR fails to fund any amounts required to be funded under the LP Agreement. The LP Agreement also requires that SI Partners distribute to us and to KKR at least 85% of distributable cash of SI Partners and its subsidiaries on a quarterly basis, subject to certain exceptions and reserves. Generally, distributions from SI Partners are made to us and KKR on a pro rata basis in accordance with our and their respective ownership interests in SI Partners. However, KKR is entitled to certain priority distributions in the event of material deviations between certain specified projected cash flows and actual cash flows. Additionally, KKR is entitled to certain priority distributions in the event a specified project that reaches a positive final investment decision does not have projected internal rates of return over a specified threshold or in the event we have not made a positive final investment decision by a certain date on specified LNG projects that are currently in development.
In addition, under the LP Agreement, both parties are granted customary registration rights in the event of an initial public offering of SI Partners, which is subject to certain consent rights of KKR.
At the closing of the transactions contemplated under the KKR Purchase Agreement, SI Partners entered into a management agreement with Sempra to engage Sempra for certain staffing and general and administrative services. The management agreement governs the services that Sempra provides to SI Partners and the charges associated with those services.
Pending Sale of NCI in SI Partners to ADIA. On December 21, 2021, Sempra entered into a purchase and sale agreement (the ADIA Purchase Agreement) with ADIA, and, solely for purposes of guaranteeing the obligations of ADIA, Infinity Investments S.A. and Azure Vista C 2020 S.à.r.l., each a wholly owned affiliate of Abu Dhabi Investment Authority, pursuant to which ADIA will acquire from Sempra, for an aggregate purchase price of $1.8 billion, subject to certain adjustments described below, a 10% NCI in SI Partners. Following the closing of the transaction pursuant to the ADIA Purchase Agreement, Sempra, KKR and ADIA will directly or indirectly own 70%, 20%, and 10%, respectively, of the outstanding Class A Units of SI Partners, which excludes the non-voting Sole Risk Interests held only by Sempra. As further described below, after the closing of the transactions under the ADIA Purchase Agreement, ADIA will have certain rights similar to those of KKR but subject to additional limitations and adjustments to take into account ADIA’s relative ownership percentage.
At December 31, 2021, SI Partners indirectly owned 99.9% of the outstanding shares of IEnova. Under the terms of the ADIA Purchase Agreement, there will be a proportional purchase price adjustment at the closing (i) for any remaining shares of IEnova that are not owned by SI Partners at the closing and (ii) that generally takes into account cash distributions made to, or capital contributions made by, the partners of SI Partners, from and after the date of the ADIA Purchase Agreement to the closing.
The closing of the transactions pursuant to the ADIA Purchase Agreement is subject to receipt of certain regulatory approvals, including from the Comisión Federal de Competencia Económica, FERC and DOE; certain other third-party approvals; the absence of a material adverse effect on the assets, businesses, properties, liabilities, financial condition or results of operations of SI Partners taken as a whole, subject to certain exceptions; and other customary closing conditions. Any party may generally terminate the ADIA Purchase Agreement if the closing has not occurred on or before September 30, 2022, subject to an automatic extension through December 21, 2022 if necessary to receive required regulatory approvals. We expect the transaction will close in the summer of 2022.
At the closing, Sempra and KKR and ADIA (the Minority Partners) will enter into a second amended and restated agreement of limited partnership of SI Partners (the Amended LP Agreement), which will govern their respective rights and obligations in respect of their ownership of SI Partners. Under the Amended LP Agreement, ADIA will have the right at the closing to designate one manager to the SI Partners board of managers. Matters are decided generally by majority vote and the managers designated by Sempra and the managers designated by each Minority Partner will each, as a group, have voting power equivalent to the ownership percentage of their respective designating limited partner. Sempra expects to maintain control of SI Partners as its 70%
owner on terms similar to those currently applicable at SI Partners. However, SI Partners and its controlled subsidiaries will be prohibited from taking certain limited actions without the prior written approval of the Minority Partners (subject to each Minority Partner maintaining certain ownership thresholds in SI Partners). The minority protections held by ADIA constitute a sub-set of the minority protections granted to KKR.
The terms of the Amended LP Agreement applicable to ADIA in relation to capital contributions and distributions are generally consistent with those granted to KKR, with adjustments and limitations to take into account ADIA’s relative ownership percentage, including limiting ADIA’s priority distribution rights to the failure of certain proposed projects to receive a positive final investment decision by a certain date or to achieve specified thresholds of projected internal rates of return or leverage. The transfer rights and restrictions and registration rights in the Amended LP Agreement applicable to ADIA are also generally consistent with those granted to KKR, with adjustments and limitations to take into account ADIA’s relative ownership percentage, including a general restriction on ADIA transferring its interests in SI Partners to third parties (other than pursuant to certain specified permitted transfers) for a specified period following its entry into the Amended LP Agreement.
SI Partners Subsidiaries. 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 addition to being traded on the NYSE, Sempra’s common stock is now also listed on the Mexican Stock Exchange under the trading symbol SRE.MX. We acquired the IEnova shares at an exchange ratio of 0.0323 shares of our common stock for each one IEnova share. In connection with the exchange offer, we recorded a $1.4 billion decrease in equity held by NCI and an increase in Sempra’s shareholders’ equity of $1.4 billion, net of $12 million in transactions costs.
In September 2021, we acquired 51,014,545 publicly owned shares of IEnova for 4.0 billion Mexican pesos (approximately $202 million in U.S. dollars) in cash upon completion of our tender offer launched in the U.S. and Mexico in August 2021, which increased our ownership interest in IEnova from 96.4% to 99.9%. We acquired these IEnova shares at a price of 78.97 Mexican pesos per share (approximately $3.95 per share in U.S. dollars). In connection with the cash tender offer, we recorded a $188 million decrease in equity held by NCI and a decrease in Sempra’s shareholders’ equity of $17 million, including $4 million in transaction costs.
As a result of the increase in our ownership interest in IEnova, we recorded an increase in Sempra’s shareholders’ equity of $72 million offset by a deferred income tax asset related to the outside basis difference in IEnova’s shares. Upon completing the sale of a 20% NCI in SI Partners to KKR in October 2021, which we discuss above, we recorded $72 million in net income tax expense related to the utilization of this deferred income tax asset.
Following the cash tender offer, 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 the 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.
In 2020, IEnova repurchased 77,122,780 shares of its outstanding common stock held by NCI for approximately $231 million, resulting in an increase in Sempra’s ownership interest in IEnova from 66.6% to 70.2%.
In 2019, IEnova repurchased 2,620,000 shares of its outstanding common stock held by NCI for approximately $10 million, resulting in an increase in Sempra’s ownership interest in IEnova from 66.5% to 66.6%.
In 2020, Sempra Infrastructure purchased additional shares in ICM Ventures Holdings B.V. for $9 million, increasing its ownership interest from 53.7% to 82.5%. ICM Ventures Holdings B.V. owns certain permits and land where Sempra Infrastructure is building a terminal for the receipt, storage and delivery of liquid fuels. In July 2021, Sempra Infrastructure acquired the remaining 17.5% interest held by NCI in ICM Ventures Holdings B.V. for $7 million.
In 2020, an affiliate of TotalEnergies SE acquired a 16.6% ownership interest in ECA LNG Phase 1.
In 2020, Sempra Infrastructure purchased for $7 million the 24.6% minority interest in Liberty Gas Storage LLC, increasing Sempra Infrastructure’s ownership in Liberty Gas Storage LLC to 100%. Prior to the purchase, the minority partner converted $22 million in notes payable due from Sempra Infrastructure to equity. As a result of the purchase, we recorded an increase in Sempra’s shareholders’ equity of $2 million for the difference between the carrying value and fair value related to the change in ownership.
In 2019, Sempra Infrastructure purchased for $20 million the 9.1% minority interest in Bay Gas immediately prior to the sale of 100% of Bay Gas.
Parent and Other
As we discuss in Note 5, in December 2021, Parent and other sold its equity interest in PXiSE.
Discontinued Operations
As we discuss in Note 5, we completed the sales of our equity interests in our Peruvian and Chilean businesses in 2020. The minority interests in Luz del Sur and Tecsur were deconsolidated upon the sale of our Peruvian businesses in April 2020, and the minority interests in Chilquinta Energía and its subsidiaries were deconsolidated upon the sale of our Chilean businesses in June 2020.
REVENUES
See Note 3 for a description of significant accounting policies for revenues.
OPERATION AND MAINTENANCE EXPENSES
Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, insurance, rent and litigation expense (except for litigation expense included in Aliso Canyon Litigation and Regulatory Matters).
FOREIGN CURRENCY TRANSLATION AND TRANSACTIONS
Our natural gas distribution utility in Mexico, Ecogas, and the majority of our former operations in South America (until our sale of these operations in 2020) use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings, but are reflected in OCI and in AOCI.
Cash flows of these consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash on Sempra’s Consolidated Statements of Cash Flows.
Foreign currency transaction (losses) gains in a currency other than Sempra Infrastructure’s functional currency were $(18) million, $(25) million and $21 million for the years ended December 31, 2021, 2020 and 2019, respectively, and are included in Other Income (Expense) , Net, on Sempra’s Consolidated Statements of Operations. Foreign currency transaction gains (losses) in a currency other than the functional currencies of our operations in South America are included in discontinued operations.
TRANSACTIONS WITH AFFILIATES
We summarize amounts due from and to unconsolidated affiliates at Sempra, SDG&E and SoCalGas in the following table.
(1) U.S. dollar-denominated loan at a variable interest rate based on 1-month LIBOR plus 196 bps (2.11% at December 31, 2020). At December 31, 2020, $1 of accrued interest receivable is included in Due from Unconsolidated Affiliates - Current. In March 2021, Sempra Infrastructure acquired the remaining 50% equity interest in ESJ that it did not already own, and ESJ became a wholly owned, consolidated subsidiary, resulting in the elimination of this note receivable.
(2) Mexican peso-denominated revolving line of credit for up to 14.2 billion Mexican pesos or approximately $691 U.S. dollar-equivalent at December 31, 2021, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps (8.06% at December 31, 2021), to finance construction of a natural gas marine pipeline. At both December 31, 2021 and 2020, $2 of accrued interest receivable is included in Due from Unconsolidated Affiliates - Current. At December 31, 2021, we classified this revolving line of credit as noncurrent because we expect to extend the maturity date on a long-term basis prior to its stated maturity date.
(3) U.S. dollar-denominated loan at a variable interest rate based on 6-month LIBOR plus 290 bps (3.16% at December 31, 2020).
(4) Amounts include principal balances plus accumulated interest outstanding.
(5) U.S. dollar-denominated loan at a fixed interest rate.
(6) SDG&E and SoCalGas are included in the consolidated income tax return of Sempra, and their respective income tax expense is computed as an amount equal to that which would result from each company having always filed a separate return.
The following table summarizes income statement information from unconsolidated affiliates.
(1) Includes net commodity costs from natural gas transactions with unconsolidated affiliates.
Sempra California
Sempra, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E and SoCalGas may make short-term advances of surplus cash to Sempra at interest rates based on the federal funds effective rate plus a margin of 13 to 20 bps, depending on the loan balance.
SoCalGas provides natural gas transportation and storage services for SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales.
SDG&E and SoCalGas charge one another, as well as other Sempra affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to O&M.
The natural gas supply for SDG&E’s and SoCalGas’ core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service; therefore, revenues and costs related to SDG&E are presented net in SoCalGas’ Statements of Operations.
SDG&E has a 20-year contract for up to 155 MW of renewable power supplied from the ESJ wind power generation facility. Prior to March 2021, ESJ was a 50% owned and unconsolidated JV of Sempra Infrastructure. In March 2021, Sempra Infrastructure completed the acquisition of the remaining 50% interest in ESJ and ESJ became a wholly owned, consolidated subsidiary of Sempra. A second 20-year contract between SDG&E and ESJ for up to 108 MW of renewable power supplied from the same facility commenced in January 2022.
Sempra Infrastructure
Sempra Infrastructure, through its indirect wholly owned subsidiaries, DEN and IEnova Pipelines, provides operating and maintenance services to TAG Pipelines Norte, S. de. R.L. de C.V., and also provides personnel under an administrative services arrangement to TAG Pipelines Norte, S. de. R.L. de C.V. and TAG JV.
Sempra Infrastructure provides certain business services to Cameron LNG JV. Sempra Infrastructure had an agreement to provide transportation services to Cameron LNG JV for capacity on the Cameron Interstate Pipeline through August 2020, when Cameron LNG JV achieved commercial operations of Train 3 of its Phase 1 project.
Sempra provided guarantees related to Cameron LNG JV’s construction-period debt, which were terminated in March 2021, as well as guarantees related to Cameron LNG JV’s SDSRA and CFIN’s Support Agreement, which remain outstanding. We discuss these guarantees in Note 6.
RESTRICTED NET ASSETS
Sempra
As we discuss below, SDG&E, SoCalGas and certain other Sempra subsidiaries have restrictions on the amount of funds that can be transferred to Sempra by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally,
certain other Sempra subsidiaries are subject to various financial and other covenants and other restrictions contained in debt and credit agreements (described in Note 7) and in other agreements that limit the amount of funds that can be transferred to Sempra. At December 31, 2021, Sempra was in compliance with all covenants related to its debt agreements.
At December 31, 2021, the amount of restricted net assets of consolidated entities of Sempra, including SDG&E and SoCalGas discussed below, that may not be distributed to Sempra in the form of a loan or dividend is $19.3 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $13.2 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries can provide to Sempra, we do not believe these restrictions will have a significant impact on our ability to access cash to pay dividends and fund operating needs.
As we discuss in Note 6, $1.5 billion of Sempra’s retained earnings represents undistributed earnings of equity method investments at December 31, 2021.
Sempra California
The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts available for dividends and loans to Sempra. At December 31, 2021, Sempra could have received combined loans and dividends of approximately $798 million from SDG&E and approximately $445 million from SoCalGas.
The payment and amount of future dividends by SDG&E and SoCalGas are at the discretion of their respective boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra from either utility:
▪The CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC-authorized percentage of each entity’s authorized capital structure. The authorized percentage at December 31, 2021 is 52% at both SDG&E and SoCalGas.
▪SDG&E and SoCalGas each have a revolving credit line that requires it to maintain a ratio of consolidated indebtedness to consolidated capitalization (as defined in the agreements) of no more than 65%, as we discuss in Note 7.
Based on these restrictions, at December 31, 2021, SDG&E’s restricted net assets were $7.5 billion and SoCalGas’ restricted net assets were $5.0 billion, which could not be transferred to Sempra.
Sempra Texas Utilities
Sempra owns an indirect, 100% interest in Oncor Holdings, which owns an 80.25% interest in Oncor. As we discuss in Note 6, we account for our investment in Oncor Holdings under the equity method. Significant restrictions at Oncor that limit the amount that may be paid as dividends to Sempra include:
▪In connection with ring-fencing measures, governance mechanisms and commitments, Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its independent directors or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements.
▪Oncor must remain in compliance with its debt-to-equity ratio established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause it to exceed its PUCT authorized debt-to-equity ratio. Oncor’s authorized regulatory capital structure is 57.5% debt to 42.5% equity at December 31, 2021.
▪If the credit rating on Oncor’s senior secured debt by any of the three major credit 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. At December 31, 2021, all of Oncor’s senior secured ratings were above BBB.
▪Oncor’s revolving credit line and certain of its other debt agreements require it to maintain a consolidated senior debt-to-capitalization ratio of no more than 65% and observe certain affirmative covenants. At December 31, 2021, Oncor was in compliance with these covenants.
Based on these restrictions, at December 31, 2021, Oncor’s restricted net assets were $12.6 billion, which could not be transferred to Sempra.
Sempra owns an indirect, 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities. Significant restrictions related to this equity method investment include:
▪Sharyland Utilities may not pay dividends or make other distributions (except for contractual payments) without the consent of the JV partner.
▪Sharyland Utilities must remain in compliance with the capital structure established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause its debt to exceed 60% of its capital structure.
▪Sharyland Utilities has a revolving credit line and a term loan credit agreement that require it to maintain a consolidated debt-to-capitalization ratio of no more than 70% and observe certain customary reporting requirements and other affirmative covenants. At December 31, 2021, Sharyland Utilities was in compliance with these and all other covenants.
Based on these restrictions, at December 31, 2021, Sharyland Utilities’ restricted net assets were $103 million, which could not be transferred to its owners.
Sempra Infrastructure
Significant restrictions at Sempra Infrastructure include:
▪Partnerships and JVs at Sempra Infrastructure may not pay dividends or make other distributions (except for contractual payments) without the consent of the partners.
▪The ADIA Purchase Agreement has certain covenants that require SI Partners to operate its business in ordinary course, including limitations on the ability to liquidate all or substantially all of the company’s assets or to sell or dispose of certain assets, from December 21, 2021 through closing or termination of the ADIA Purchase Agreement. Under these restrictions, net assets of SI Partners totaling $6.8 billion, including the $193 million minimum legal reserves and $20 million restricted cash that we describe below, are restricted at December 31, 2021.
▪Sempra Infrastructure has an equity method investment in Cameron LNG JV, which has debt agreements that require the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The debt agreements require the JV to maintain reserve accounts in order to pay the project debt service, and also contain restrictions related to the payment of dividends and other distributions to the members of the JV. We discuss Cameron LNG JV’s debt agreements and the associated Sempra guarantees in Note 6. Under these restrictions, net assets of Cameron LNG JV of approximately $395 million are restricted at December 31, 2021.
▪Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $193 million at Sempra Infrastructure’s consolidated Mexican subsidiaries at December 31, 2021
▪IEnova has restrictions under trust and debt agreements related to pipeline projects to pay for rights-of-way, license fees, permits, topographic surveys and other costs. Under these restrictions, net assets totaling $20 million are restricted at December 31, 2021.
▪TAG JV, a 50% owned and unconsolidated JV of Sempra Infrastructure, has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under these restrictions, net assets totaling $66 million are restricted at December 31, 2021.
OTHER INCOME (EXPENSE), NET
Other Income (Expense), Net on the Consolidated Statements of Operations consists of the following:
(1) Represents net investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are offset by corresponding changes in compensation expense related to the plans, recorded in O&M on the Consolidated Statements of Operations.
(2) Includes losses of $23 in 2021, losses of $42 in 2020 and gains of $30 in 2019 from translation to U.S. dollars of a Mexican peso-denominated loan to IMG JV, which are offset by corresponding amounts included in Equity Earnings on the Consolidated Statements of Operations.
NOTE 2. NEW ACCOUNTING STANDARDS
We describe below recent accounting pronouncements that have had or may have a significant effect on our results of operations, financial condition, cash flows or disclosures.
ASU 2020-06, “Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity”: ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. In addition to other changes, this standard amends ASC 470-20, “Debt with Conversion and Other Options,” by removing the accounting models for instruments with beneficial and cash conversion features. The standard also amends certain guidance in ASC 260, “Earnings Per Share,” for the computation of EPS for convertible instruments and contracts on an entity’s own equity. For public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. An entity can use either a full or modified retrospective approach to adopt ASU 2020-06 and must disclose, in the period of adoption, EPS transition information about the effect of the change on affected per-share amounts. We will adopt the standard on January 1, 2022 using a modified retrospective approach and do not expect the adoption will materially impact our financial statements or per-share amounts.
NOTE 3. REVENUES
The following table disaggregates our revenues from contracts with customers by major service line and market and provides a reconciliation to total revenues by segment. The majority of our revenue is recognized over time.
REVENUES FROM CONTRACTS WITH CUSTOMERS
Our revenues from contracts with customers are primarily related to the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity through our regulated utilities. We also provide other midstream and renewable energy-related services. We assess our revenues on a contract-by-contract basis as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.
We generally recognize revenues when performance of the promised commodity service is provided to our customers and we invoice our customers for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of natural gas and electricity and providing of natural gas storage services as ongoing and integrated services. Generally, natural gas or electricity services are received and consumed by the customer simultaneously. Our performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of our performance obligations can be directly measured by the amount of natural gas or electricity delivered to the customer. In most cases, the right to consideration from the customer directly corresponds to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice.
The payment terms in our customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.
We exclude sales and usage-based taxes from revenues. In addition, SDG&E and SoCalGas pay franchise fees to operate in various municipalities. SDG&E and SoCalGas bill these franchise fees to their customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SDG&E’s and SoCalGas’ ability to collect from the customer, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.
Utilities Revenues
Utilities revenues represent the majority of our consolidated revenues from contracts with customers and include:
▪The transmission, distribution and storage of natural gas at:
◦SDG&E
◦SoCalGas
◦Sempra Infrastructure’s Ecogas
▪The generation, transmission and distribution of electricity at SDG&E.
Utilities revenues are derived from and recognized upon the delivery of natural gas or electricity services to customers. Amounts that we bill our customers are based on tariffs set by regulators within the respective state or country. For SDG&E and SoCalGas, which follow the provisions of U.S. GAAP governing rate-regulated operations as we discuss in Note 1, amounts that we bill to customers also include adjustments for previously recognized regulatory revenues.
SDG&E, SoCalGas and Ecogas recognize revenues based on regulator-approved revenue requirements, which allow the utilities to recover their reasonable operating costs and provides the opportunity to realize their authorized rates of return on their investments. While SDG&E’s and SoCalGas’ revenues are not affected by actual sales volumes, the pattern of their revenue recognition during the year is affected by seasonality. SDG&E and SoCalGas recognize annual authorized revenue for customers using seasonal factors established in applicable proceedings. This generally results in a significant portion of operating revenues being recognized in the third quarter of each year for SDG&E and in the first and fourth quarters of each year for SoCalGas.
SDG&E has an arrangement to provide the California ISO with the ability to control its high-voltage transmission lines for prices approved by the FERC. Revenue is recognized over time as access is provided to the California ISO.
Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings, which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.
SDG&E and SoCalGas recognize revenues from the sale of allocated California GHG emissions allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and SDG&E and SoCalGas have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts.
Energy-Related Businesses Revenues
Revenues at Sempra Infrastructure typically represent revenues from long-term, U.S. dollar-based contracts with customers for the sale of natural gas and LNG, as well as storage and transportation of natural gas. Invoiced amounts are based on the volume of natural gas delivered and contracted prices.
We recognize storage revenue from firm capacity reservation agreements, under which we collect a fee for reserving storage capacity for customers in our storage facilities. Under these firm agreements, customers pay a monthly fixed reservation fee based
on the storage capacity reserved rather than the actual volumes stored. For the fixed-fee component, revenue is recognized on a straight-line basis over the term of the contract. We bill customers for any capacity used in excess of the contracted capacity and such revenues are recognized in the month of occurrence. We also recognize revenue for interruptible storage services. As we discuss in Note 5, in February 2019, Sempra Infrastructure completed the sale of its non-utility natural gas storage assets in the southeast U.S. (comprised of Mississippi Hub and Bay Gas).
We generate pipeline transportation revenues from firm agreements, under which customers pay a fee for reserving transportation capacity. Revenue is recognized when the volumes are delivered to the customers’ agreed upon delivery point. We recognize revenues for our stand-ready obligation to provide capacity and transportation services throughout the contractual delivery period, as the benefits are received and consumed simultaneously as customers utilize pipeline capacity for the transport and receipt of natural gas and LPG. Invoiced amounts are based on a variable usage fee and a fixed capacity charge, adjusted for the Consumer Price Index, the effects of any foreign currency translation and the actual quantity of commodity transported.
Sempra Infrastructure and, previously, Sempra Renewables develop, invest in and operate solar and wind facilities that have long-term PPAs to sell the electricity and the related green energy attributes they generate to customers, generally load serving entities, and also for Sempra Infrastructure, industrial and other customers. Load serving entities will sell electric service to their end-users and wholesale customers immediately upon receipt of our power delivery, and industrial and other customers immediately consume the electricity to run their facilities, and thus, we recognize the revenue under the PPAs as the electricity is generated and delivered. We invoice customers based on the volume of energy delivered at rates pursuant to the PPAs. As we discuss in Note 5, in April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments.
TdM is a natural gas-fired power plant that generates revenues from selling electricity and/or resource adequacy to the California ISO and to governmental, public utility and wholesale power marketing entities, as the power is delivered at the interconnection point.
Sempra Infrastructure sells natural gas to the CFE and other customers under supply agreements. Sempra Infrastructure recognizes the revenue from the sale of natural gas upon transfer of the natural gas via pipelines to customers at the agreed upon delivery points, and in the case of the CFE, at its thermoelectric power plants.
Remaining Performance Obligations
We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) variable consideration recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.
For contracts greater than one year, at December 31, 2021, we expect to recognize revenue related to the fixed fee component of the consideration as shown below. Sempra’s remaining performance obligations primarily relate to capacity agreements for natural gas storage and transportation at Sempra Infrastructure. SoCalGas did not have any remaining performance obligations at December 31, 2021.
(1) Excludes intercompany transactions.
Contract Liabilities from Revenues from Contracts with Customers
From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.
Activities within Sempra’s and SDG&E’s contract liabilities are presented below. There were no contract liabilities at SoCalGas in 2021, 2020 or 2019.
(1) Balances at December 31, 2021, 2020 and 2019 include $116, $52 and $4, respectively, in Other Current Liabilities and $162, $155 and $159, respectively, in Deferred Credits and Other.
(2) Balances at December 31, 2021, 2020 and 2019 include $4, $4 and $4, respectively, in Other Current Liabilities and $79, $83 and $87, respectively, in Deferred Credits and Other.
Receivables from Revenues from Contracts with Customers
The table below shows receivable balances associated with revenues from contracts with customers on the Consolidated Balance Sheets.
(1) Amount is presented net of amounts due to unconsolidated affiliates on the Consolidated Balance Sheets, when right of offset exists.
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.
REVENUES FROM SOURCES OTHER THAN CONTRACTS WITH CUSTOMERS
Certain of our revenues are derived from sources other than contracts with customers and are accounted for under other accounting standards outside the scope of ASC 606.
Utilities Regulatory Revenues
Alternative Revenue Programs
We recognize revenues from alternative revenue programs when the regulator-specified conditions for recognition have been met and adjust these revenues as they are recovered or refunded through future utility service.
Decoupled revenues. As discussed earlier, the regulatory framework requires SDG&E and SoCalGas to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for natural gas and electricity will generally vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for SDG&E and SoCalGas to use a “decoupling” mechanism, which allows SDG&E and SoCalGas to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.
Incentive mechanisms. The CPUC applies performance-based measures and incentive mechanisms to all California IOUs, under which SDG&E and SoCalGas have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.
Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.
Other Cost-Based Regulatory Recovery
The CPUC, and the FERC as it relates to SDG&E, authorize SDG&E and SoCalGas to collect revenue requirements for operating costs and capital related costs (such as depreciation, taxes and return on rate base) from customers, 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 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.
We discuss balancing accounts and their effects further in Note 4.
Other Revenues
Sempra Infrastructure generates lease revenues from certain of its natural gas and ethane pipelines, compressor stations, LPG storage facilities, a rail facility and liquid fuels terminals. Certain PPAs at Sempra Renewables were accounted for as operating leases prior to sale of its wind assets in April 2019. We discuss the recognition of lease income in Note 16 of the Notes to Consolidated Financial Statements.
Sempra Infrastructure has an agreement with Tangguh PSC to supply LNG to the ECA Regas Facility. Under the terms of the agreement, Tangguh PSC must either deliver the contracted number of cargoes or pay a diversion fee for non-delivery of LNG cargoes.
Sempra Infrastructure also recognizes other revenues associated with derivatives related to the sales of natural gas and electricity under short-term and long-term contracts and into the spot market and other competitive markets. Revenues include the net realized gains and losses on physical and derivative settlements and net unrealized gains and losses from the change in fair values of these derivatives.
NOTE 4. REGULATORY MATTERS
REGULATORY ASSETS AND LIABILITIES
We show the details of regulatory assets and liabilities in the following table and discuss them below. With the exception of regulatory balancing accounts, we generally do not earn a return on our regulatory assets until such time as a related cash expenditure has been made. Upon the occurrence of a cash expenditure associated with a regulatory asset, the related amounts are recoverable through a regulatory account mechanism for which we earn a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate. The periods during which we recognize a regulatory asset while we do not earn a return vary by regulatory asset.
(1) At December 31, 2021, 2020 and 2019, the noncurrent portion of regulatory balancing accounts - net undercollected for SDG&E was $358, $139 and $108, respectively, and for SoCalGas was $410, $218 and $500, respectively.
(2) Includes regulatory assets earning a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate.
Regulatory Assets Not Earning a Return
▪Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. The related amounts are recovered in rates once these contracts are settled, generally within two years.
▪Deferred income taxes recoverable/refundable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Infrastructure expect to recover/refund net regulatory assets/liabilities related to deferred income taxes over the lives of the assets, ranging from 5 to 69 years, that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities include excess deferred income taxes resulting from statutory income tax rate changes and certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 8.
▪Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets. The assets are recovered in rates as the plans are funded.
▪The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.
▪Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).
▪Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.
▪The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 48-year period.
Regulatory Assets Earning a Return
▪Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized amounts. Depreciation, taxes and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. The adopted revenue requirements in the 2019 GRC FD associated with the period from January 1, 2019 through December 31, 2019 were recovered in rates over a 24-month period that began in January 2020.
Amortization expense on certain regulatory assets for the years ended December 31, 2021, 2020 and 2019 was $10 million, $9 million and $7 million, respectively, at Sempra, $5 million, $4 million and $3 million, respectively, at SDG&E, and $5 million, $5 million and $4 million, respectively, at SoCalGas.
SEMPRA CALIFORNIA
COVID-19 Pandemic Protections
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.
Disconnection OIR
In June 2020, the CPUC issued a decision to adopt certain customer protections to reduce residential customer disconnections and improve reconnection processes, including, among other things, imposing limitations on service disconnections, elimination of deposit requirements and reconnection fees, establishment of the AMP that provides successfully participating, income-qualified residential customers with relief from outstanding utility bill amounts, and increased outreach and marketing efforts. As permitted by the decision, SDG&E and SoCalGas have each established a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding utility bill amounts provided under the AMP.
CPUC GRC
The CPUC uses GRCs to set rates designed to allow SDG&E and SoCalGas to recover their reasonable operating costs and to provide the opportunity to realize their authorized rates of return on their investments.
In September 2019, the CPUC issued a final decision in the 2019 GRC approving SDG&E’s and SoCalGas’ test year revenues for 2019 and attrition year adjustments for 2020 and 2021, which was effective retroactively to January 1, 2019. This is the first GRC that includes revenues authorized for risk assessment mitigation phase activities.
The 2019 GRC FD approved a test year 2019 revenue requirement of $1,990 million for SDG&E’s combined operations ($1,590 million for its electric operations and $400 million for its natural gas operations) and $2,770 million for SoCalGas.
The increases include separately authorized components for O&M and capital-related costs, as follows:
In January 2020, the CPUC issued a final decision implementing a four-year GRC cycle for California IOUs. SDG&E and SoCalGas were directed to file a petition for modification to revise their 2019 GRC to add two additional attrition years, resulting in a transitional five-year GRC period (2019-2023). In May 2021, the CPUC issued a final decision approving SDG&E’s and SoCalGas’ request to continue their authorized post-test year mechanisms for 2022 and 2023. For SDG&E, the decision authorizes revenue requirement increases of $87 million (3.92%) for 2022 and $86 million (3.70%) for 2023. For SoCalGas, the decision authorizes revenue requirement increases of $142 million (4.53%) for 2022 and $130 million (3.97%) for 2023.
The 2019 GRC FD approved SDG&E’s and SoCalGas’ establishment of two-way liability insurance premium balancing accounts, including wildfire insurance premium costs based on a specific level of coverage. The 2019 GRC FD also permits SDG&E and SoCalGas to seek recovery of additional liability insurance coverage.
The 2019 GRC FD clarified that differences between incurred and forecasted income tax expense due to forecasting differences are not subject to tracking in the income tax expense memorandum account beginning in 2019. SDG&E and SoCalGas previously recorded regulatory liabilities, inclusive of interest, associated with the 2016 through 2018 tracked forecasting differences of $86 million and $89 million, respectively. In April 2020, the CPUC confirmed treatment of the two-way income tax expense memorandum account for these 2016 through 2018 balances, at which time SDG&E and SoCalGas released these regulatory liability balances to revenues and regulatory interest.
CPUC Cost of Capital
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 (shown in the table below) 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.
SDG&E
FERC Rate Matters
SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets.
SDG&E’s TO4 ROE of 10.05% was the basis of SDG&E’s FERC-related revenue recognition until March 2020, when the FERC approved the settlement terms that SDG&E and all settling parties reached in October 2019 on SDG&E’s TO5 filing. The settlement agreement provided for a ROE of 10.60%, consisting of a base ROE of 10.10% plus an additional 50 bps for participation in the California ISO (the California ISO adder). If the FERC issues an order ruling that California IOUs are no longer eligible for the California ISO adder, SDG&E would refund the California ISO adder as of the refund effective date (June 1, 2019) if such a refund is determined to be required by the terms of the TO5 settlement. The TO5 term is effective June 1, 2019 and shall remain in effect each calendar quarter until terminated by a notice at least six months before the end of the calendar year. In 2020, SDG&E recorded retroactive revenues of $12 million related to 2019, and additional FERC revenues of $17 million to conclude a rate base matter, net of certain refunds to be paid to CPUC-jurisdictional customers.
Energy Efficiency Program Inquiry
In January 2020, the CPUC issued a ruling seeking comments on a report prepared by its consultant regarding SDG&E’s Upstream Lighting Program for the program year 2017. The CPUC subsequently expanded the scope of the comments to cover the program year 2018. The Upstream Lighting Program was one of SDG&E’s Energy Efficiency Programs designed to produce energy efficiency savings for which SDG&E could earn a performance-based incentive.
Pursuant to the CPUC ruling, intervenors representing ratepayers questioned SDG&E’s management of the program and alleged that certain program expenditures did not benefit the purpose of the program. As a result of the inquiry, SDG&E voluntarily expanded its review to include the program year 2019. Based on this review, SDG&E concluded that some concessions were appropriate, which include refunding certain costs to customers and reducing certain performance-based incentives. Accordingly, in the year ended December 31, 2020, SDG&E reduced revenues by $51 million and recorded a fine of $6 million in Other (Expense) Income, Net, on the SDG&E and Sempra Consolidated Statements of Operations. The after-tax impact for the year ended December 31, 2020 was $44 million. In October 2020, SDG&E executed a settlement agreement with intervenors consistent with these concessions. In September 2021, the CPUC approved the settlement agreement.
SOCALGAS
OSCs - Energy Efficiency and Advocacy
In October 2019, the CPUC issued an OSC to determine whether SoCalGas should be sanctioned for violation of certain CPUC code sections and orders relating to energy efficiency (EE) codes and standards advocacy activities, undertaken by SoCalGas following a CPUC decision disallowing SoCalGas’ future engagement in advocacy around such EE codes and standards. On February 3, 2022, the assigned Administrative Law Judge issued a Presiding Officer’s Decision (POD 1) that found that SoCalGas did undertake prohibited EE codes and standards advocacy activities using ratepayer funds. POD 1 imposes on SoCalGas a financial penalty of $10 million; customer refunds for certain ratepayer expenditures and shareholder incentives that SoCalGas estimates will be negligible; and a prohibition from recovering from ratepayers costs of proposed codes and standards activities until SoCalGas demonstrates policies, practices and procedures that adhere to the CPUC’s intent for codes and standards advocacy. POD 1 can be appealed within 30 days or be reviewed by any of the CPUC commissioners. If there are no appeals or commissioner requests for review, POD 1 automatically becomes the final decision of the CPUC. SoCalGas does not intend to appeal POD 1.
In December 2019, the CPUC issued a second OSC to determine whether SoCalGas is entitled to the EE program’s shareholder incentives for codes and standards advocacy in 2016 and 2017 (later expanded to include 2014 and 2015), whether its shareholders should bear the costs of those advocacy activities, and to address whether any other remedies are appropriate. In April 2021, the assigned Administrative Law Judge issued a Presiding Officer’s Decision (POD 2) on this second OSC. POD 2 finds no violations and assesses no fines or penalties but finds that SoCalGas spent ratepayer funds on activities that were not aligned with the CPUC’s intent for EE codes and standards advocacy, and orders customer refunds that SoCalGas estimates will be negligible. Additionally, POD 2 precludes SoCalGas from seeking cost recovery associated with EE codes and standards advocacy programs until lifted by the CPUC, and orders certain nonfinancial remedies. POD 2 was appealed by intervenors and in February 2022, the assigned Administrative Law Judge issued a modified POD 2 that substantially retains the original conclusions, including no fines or penalties. Also, in February 2022, a CPUC commissioner issued an alternative decision that imposes a financial penalty of $150,000. SoCalGas expects that both the modified POD 2 and the CPUC commissioner’s alternative decision will be heard at a CPUC meeting in March 2022.
If the CPUC were to assess fines, penalties or other restrictions on SoCalGas that are different from what has been ordered in POD 1 and the modified POD 2, they could be material to SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
NOTE 5. ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS
ACQUISITIONS
Sempra Texas Utilities
Sharyland Holdings
In May 2019, Sempra acquired an indirect, 50% interest in Sharyland Holdings for $95 million (net of $7 million in post-closing adjustments). In connection with and prior to the consummation of the acquisition, Sharyland Holdings owned 100% of the membership interests in Sharyland Utilities, LP and Sharyland Utilities, LP converted into a limited liability company, named Sharyland Utilities, L.L.C. We account for our indirect, 50% interest in Sharyland Holdings as an equity method investment.
Sempra Infrastructure
ESJ
In March 2021, Sempra Infrastructure completed the acquisition of Saavi Energía’s 50% equity interest in ESJ for a purchase price of $65 million (net of $14 million of acquired cash and cash equivalents) plus the assumption of $277 million in debt (including $94 million owed from ESJ to Sempra Infrastructure that eliminates upon consolidation). Sempra Infrastructure previously accounted for its 50% interest in ESJ as an equity method investment. This acquisition increased Sempra Infrastructure’s ownership interest in ESJ from 50% to 100%. We accounted for this asset acquisition using a cost accumulation model whereby the cost of the acquisition and carrying value of our previously held interest in ESJ ($34 million) were allocated to
assets acquired ($458 million) and liabilities assumed ($345 million) based on their relative fair values. ESJ owns a fully operating wind power generation facility with a nameplate capacity of 155 MW that is fully contracted by SDG&E under a long-term PPA. Sempra Infrastructure recorded a $190 million intangible asset for the relative fair value of the PPA that will be amortized over a period of 14 years against revenues. On January 15, 2022, ESJ completed construction and began commercial operation of a second wind power generation facility with a nameplate capacity of 108 MW that is also fully contracted by SDG&E under a long-term PPA.
DIVESTITURES
Sempra Infrastructure
In February 2019, Sempra Infrastructure completed the sale of its non-utility natural gas storage assets in the southeast U.S. (comprised of Mississippi Hub and Bay Gas), which we classified as held for sale at December 31, 2018, and received cash proceeds of $322 million, net of transaction costs. In January 2019, Sempra Infrastructure completed the sale of other non-utility assets for $5 million.
Sempra Renewables
In April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments for $569 million, net of transaction costs, and recorded a $61 million ($45 million after tax and NCI) gain, which is included in Gain on Sale of Assets on Sempra’s Consolidated Statements of Operations. Upon completion of the sale, remaining nominal business activities at Sempra Renewables were subsumed into Parent and other and the Sempra Renewables segment ceased to exist.
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.
DISCONTINUED OPERATIONS
In January 2019, our board of directors approved a plan to sell our South American businesses. We present these businesses, which previously constituted the Sempra South American Utilities segment, and certain activities associated with those businesses as discontinued operations.
In April 2020, we completed the sale of our equity interests in our Peruvian businesses, including our 83.6% interest in Luz del Sur and our interest in Tecsur, to an affiliate of China Yangtze Power International (Hongkong) Co., Limited for cash proceeds of $3,549 million, net of transaction costs and as adjusted for post-closing adjustments, and recorded a pretax gain of $2,271 million ($1,499 million after tax).
In June 2020, we completed the sale of our equity interests in our Chilean businesses, including our 100% interest in Chilquinta Energía and Tecnored and our 50% interest in Eletrans, to State Grid International Development Limited for cash proceeds of $2,216 million, net of transaction costs and as adjusted for post-closing adjustments, and recorded a pretax gain of $628 million ($248 million after tax).
In the year ended December 31, 2020, the pretax gains from the sales of our South American businesses are included in Gain on Sale of Discontinued Operations in the table below and the after-tax gains are included in Income from Discontinued Operations, Net of Income Tax, on Sempra’s Consolidated Statements of Operations.
Summarized results from discontinued operations were as follows:
(1) Results include activity until deconsolidation of our Peruvian businesses on April 24, 2020 and Chilean businesses on June 24, 2020 and post-closing adjustments related to the sales of these businesses.
The following table summarizes the carrying amounts of the major classes of assets and related liabilities classified as held for sale in discontinued operations.
(1) Primarily represents funds held in accordance with Peruvian tax law.
As a result of the sales of our South American businesses, in 2020, we reclassified $645 million of cumulative foreign currency translation losses from AOCI to Gain on Sale of Discontinued Operations, which is included in Income from Discontinued Operations, Net of Income Tax, on Sempra’s Consolidated Statements of Operations.
NOTE 6. INVESTMENTS IN UNCONSOLIDATED ENTITIES
We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. Equity earnings and losses, both before and net of income tax, are combined and presented as Equity Earnings on the Consolidated Statements of Operations.
Our equity method investments include various domestic and foreign entities. Our domestic equity method investees are typically partnerships that are pass-through entities for income tax purposes and therefore they do not record income tax. Sempra’s income tax on earnings from these equity method investees, other than Oncor Holdings as we discuss below, is included in Income Tax Expense on the Consolidated Statements of Operations. Our foreign equity method investees are generally corporations whose operations are taxable on a standalone basis in the countries in which they operate, and we recognize our equity in such income or loss net of investee income tax. See Note 8 for information on how equity earnings and losses before income taxes are factored into the calculations of our pretax income or loss and ETR.
We provide the carrying values of our investments and earnings (losses) on these investments in the following tables.
(1) The carrying value of our equity method investment is $2,844, $2,833 and $2,823 higher than the underlying equity in the net assets of the investee at December 31, 2021, 2020 and 2019, respectively, due to $2,868 of equity method goodwill and $69 in basis differences in AOCI, offset by $93, $104 and $114 at December 31, 2021, 2020 and 2019, respectively, due to a tax sharing liability to TTI under a tax sharing agreement.
(2) The carrying value of our equity method investment is $42 higher than the underlying equity in the net assets of the investee due to equity method goodwill.
(3) The carrying value of our equity method investment is $276, $259 and $263 higher than the underlying equity in the net assets of the investee at December 31, 2021, 2020 and 2019, respectively, primarily due to guarantees, which we discuss below, interest capitalized on the investment prior to the JV commencing its planned principal operations in August 2019 and amortization of guarantee fees and capitalized interest thereafter.
(4) In March 2021, Sempra Infrastructure completed the acquisition of the remaining 50% interest in ESJ and ESJ became a wholly owned, consolidated subsidiary. After the acquisition, ESJ is no longer accounted for as an equity method investment. The carrying value of our equity method investment is $12 higher than the underlying equity in the net assets of the investee at December 31, 2020 and 2019 due to the remeasurement of our retained investment to fair value in 2014.
(5) The carrying value of our equity method investment is $5 higher than the underlying equity in the net assets of the investee due to guarantees.
(6) The carrying value of our equity method investment is $130 higher than the underlying equity in the net assets of the investee due to equity method goodwill.
(1) We provide our ETR calculation in Note 8.
(2) Includes $3 of basis differences in equity earnings related to AOCI in 2021.
We disclose distributions received from our investments, by segment, in the table below.
At December 31, 2021, 2020 and 2019 our share of the undistributed earnings of equity method investments was $1.5 billion, $1.1 billion and $634 million, respectively, including $1.1 billion at December 31, 2021 in undistributed earnings from investments for which we have more than 50% equity interests.
SEMPRA TEXAS UTILITIES
Oncor Holdings
We account for our 100% ownership interest in Oncor Holdings, which owns an 80.25% interest in Oncor, as an equity method investment. Sempra does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments in effect 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. We also have limited representation on the Oncor Holdings and Oncor boards of directors.
Oncor is a domestic partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra. Rather, only our pretax equity earnings from our investment in Oncor Holdings (a disregarded entity for tax purposes) are included in our consolidated income tax return. A tax sharing agreement with TTI, Oncor Holdings and Oncor provides for the calculation of an income tax liability substantially as if Oncor Holdings and Oncor were taxed as corporations and requires tax
payments determined on that basis. While partnerships are not subject to income taxes, in consideration of the tax sharing agreement and Oncor being subject to the provisions of U.S. GAAP governing rate-regulated operations, Oncor recognizes amounts determined under cost-based regulatory rate-setting processes (with such costs including income taxes), as if it were taxed as a corporation. As a result, since Oncor Holdings consolidates Oncor, we recognize equity earnings from our investment in Oncor Holdings net of its recorded income tax.
We provide summarized income statement and balance sheet information for Oncor Holdings in the following table.
(1) Excludes adjustments to equity earnings related to amortization of a tax sharing liability associated with a tax sharing arrangement and changes in basis differences in AOCI within the carrying value of our equity method investment.
In 2021, 2020 and 2019, Sempra contributed $566 million, $632 million and $1,587 million, respectively, to Oncor Holdings, including $1,067 million in 2019 to fund Oncor’s May 2019 acquisition of interests in InfraREIT and certain acquisition-related expenses.
Sharyland Holdings
As we discuss in Note 5, in May 2019, we acquired an indirect, 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities, for $95 million, net of $7 million in post-closing adjustments, which we account for as an equity method investment. In 2019, we invested cash of $3 million in Sharyland Holdings.
SEMPRA INFRASTRUCTURE
Cameron LNG JV
Cameron LNG JV was formed in October 2014 and is a JV between Sempra and three project partners, TotalEnergies SE, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha. We account for our 50.2% investment in Cameron LNG JV under the equity method.
Cameron LNG JV operates a three-train natural gas liquefaction export facility with a nameplate capacity of 13.9 Mtpa of LNG, with an export capacity of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Cameron LNG JV achieved commercial operations of Train 1, Train 2 and Train 3 under its tolling agreements in August 2019, February 2020 and August 2020, respectively. Prior to commencing full commercial operations, Sempra Infrastructure capitalized interest of $33 million in 2019 related to this equity method investment. In 2021, 2020 and 2019, Sempra Infrastructure contributed $2 million, $54 million and $77 million, respectively, to Cameron LNG JV.
Cameron LNG JV Financing
General. In August 2014, Cameron LNG JV entered into finance documents (collectively, Loan Facility Agreements) for senior secured financing in an initial aggregate principal amount of up to $7.4 billion under three debt facilities provided by the Japan Bank for International Cooperation (JBIC) and 29 international commercial banks, some of which will benefit from insurance coverage provided by Nippon Export and Investment Insurance (NEXI). The Loan Facility Agreements and related finance documents provide senior secured term loans with a maturity date of July 15, 2030. The proceeds of the loans were used for financing the cost of development and construction of the three-train Cameron LNG JV project. The Loan Facility Agreements and related finance documents contain customary representations and affirmative and negative covenants for project finance facilities of this kind with the lenders of the type participating in the Cameron LNG JV financing.
In December 2019, Cameron LNG JV refinanced the commercial bank portion of the Loan Facility Agreements not covered by NEXI with $3.0 billion of senior secured notes issued in a private placement bond offering. The senior secured notes bear interest at a weighted-average fixed rate of 3.39% at December 31, 2021 with maturity dates ranging between 2031 and 2039.
Interest. The weighted-average all-in cost of the loans that remain outstanding under the original Loan Facility Agreements is 0.98% per annum over LIBOR prior to financial completion of the project and 1.22% per annum over LIBOR following financial completion of the project. In November 2014, Cameron LNG JV entered into floating-to-fixed interest rate swaps for approximately $3.7 billion notional amount, resulting in an effective fixed rate of 3.19% for the LIBOR component of the interest rate on the loans. In June 2015, Cameron LNG JV entered into additional floating-to-fixed interest rate swaps effective starting in 2020, for approximately $1.5 billion notional amount, resulting in an effective fixed rate of 3.32% for the LIBOR component of the interest rate on the loans. In December 2019, approximately $790 million of the $1.5 billion notional amount was terminated as a result of the refinancing, resulting in an effective fixed rate of 3.26% for the LIBOR component of the interest rate on the remaining loans outstanding.
The weighted-average all-in cost of the loans outstanding under the original Loan Facility Agreements and the newly issued senior secured notes is 3.69%.
Guarantees. In March 2021, Cameron LNG JV reached financial completion of the three-train liquefaction project, and Sempra’s guarantees related to agreements entered into in August 2014 and December 2019, for the benefit of all of Cameron LNG JV’s creditors under the original Loan Facility Agreements and the senior secured notes, were terminated.
In August 2014, Sempra and the other project owners entered into a transfer restrictions agreement with Société Générale, as intercreditor agent for the lenders under the Loan Facility Agreements. Pursuant to the transfer restriction agreement, starting six months after financial completion of the three-train Cameron LNG JV project, Sempra must retain at least 10% of the indirect fully diluted economic and beneficial ownership interest in Cameron LNG JV. In addition, at all times, a Sempra controlled (but not necessarily wholly owned) subsidiary must directly own 50.2% of the membership interests of Cameron LNG JV.
Events of Default. Cameron LNG JV’s Loan Facility Agreements and related finance documents contain events of default customary for such financings, including events of default for: failure to pay principal and interest when due; insolvency of Cameron LNG JV; abandonment of the project; expropriation; and unenforceability or termination of the finance documents.
Security. To support Cameron LNG JV’s obligations under its debt agreements, Cameron LNG JV has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG JV were pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG JV by Sempra and the other project partners.
Sempra Promissory Note for SDSRA Distribution
Cameron LNG JV’s debt agreements require Cameron LNG JV to maintain the SDSRA, which is an additional reserve account beyond the Senior Debt Service Accrual Account, where funds accumulate from operations to satisfy senior debt obligations due and payable on the next payment date. Both accounts can be funded with cash or authorized investments. In June 2021, Sempra Infrastructure received a distribution of $165 million based on its proportionate share of the SDSRA, for which Sempra provided a promissory note and letters of credit to secure a proportionate share of Cameron LNG JV’s obligation to fund the SDSRA. Sempra’s maximum exposure to loss is replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA, or $165 million. We recorded a guarantee liability of $22 million in June 2021, with an associated carrying value of $22 million at December 31, 2021, for the fair value of the promissory note, which is being reduced over the duration of the guarantee through Sempra Infrastructure’s investment in Cameron LNG JV. 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.
Sempra Support Agreement for CFIN
In July 2020, CFIN entered into a financing arrangement with Cameron LNG JV’s four project owners and received aggregate proceeds of $1.5 billion from two project owners and from external lenders on behalf of the other two project owners (collectively, the affiliate loans), based on their proportionate ownership interest in Cameron LNG JV. CFIN used the proceeds from the affiliate loans to provide a loan to Cameron LNG JV. The affiliate loans mature in 2039. Principal and interest will be paid from Cameron LNG JV’s project cash flows from its three-train natural gas liquefaction facility. Cameron LNG JV used the proceeds from its loan to return equity to its project owners. Sempra used its $753 million share of the proceeds for working capital and other general corporate purposes, including the repayment of indebtedness.
Sempra Infrastructure’s $753 million proportionate share of the affiliate loans, based on its 50.2% ownership interest in Cameron LNG JV, was funded by external lenders comprised of a syndicate of eight banks (the bank debt) to whom Sempra has provided a guarantee pursuant to a Support Agreement, as amended on June 29, 2021, under which:
▪Sempra has severally guaranteed repayment of the bank debt plus accrued and unpaid interest if CFIN fails to pay the external lenders;
▪the external lenders may exercise an option to put the bank debt to Sempra Infrastructure upon the occurrence of certain events, including a failure by CFIN to meet its payment obligations under the bank debt;
▪the external lenders will put some or all of the bank debt to Sempra Infrastructure on the fifth, tenth, or fifteenth anniversary date of the affiliate loans, except the portion of the debt owed to any external lender that has elected not to participate in the put option six months prior to the respective anniversary date;
▪Sempra Infrastructure also has a right to call the bank debt back from, or to refinance the bank debt with, the external lenders at any time; and
▪the Support Agreement will terminate upon full repayment of the bank debt, including repayment following an event in which the bank debt is put to Sempra Infrastructure.
In exchange for this guarantee, the external lenders will pay a guarantee fee that is based on the credit rating of Sempra’s long-term senior unsecured non-credit enhanced debt rating, which guarantee fee Sempra Infrastructure will recognize as interest income as earned. Sempra’s maximum exposure to loss is the bank debt plus any accrued and unpaid interest and related fees, subject to a liability cap of 130% of the bank debt, or $979 million. We measure the Support Agreement at fair value, net of related guarantee fees, on a recurring basis (see Note 12). At December 31, 2021, the fair value of the Support Agreement was $7 million, which is included in Other Current Assets on Sempra’s Consolidated Balance Sheet.
ESJ JV
As we discuss in Note 5, in March 2021, Sempra Infrastructure completed the acquisition of the remaining 50% equity interest in ESJ and ESJ became a wholly owned, consolidated subsidiary. Prior to the acquisition date, Sempra Infrastructure owned 50% of ESJ and accounted for its interest as an equity method investment.
IMG JV
Sempra Infrastructure has a 40% interest in IMG JV, a JV with a subsidiary of TC Energy Corporation, and accounts for its interest as an equity method investment. IMG JV owns and operates the Sur de Texas-Tuxpan natural gas marine pipeline, which is fully contracted under a 35-year natural gas transportation service contract with the CFE and commenced commercial operations in September 2019.
SEMPRA RENEWABLES
Sempra Renewables completed the sale of its remaining wind assets and investments in April 2019. We discuss this divestiture further in Note 5.
RBS SEMPRA COMMODITIES
RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra and RBS in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. Since 2011, our investment balance has reflected our share of the remaining partnership assets, including amounts retained by the partnership to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the
partnership and the distribution of the partnership’s remaining assets, if any. We account for our investment in RBS Sempra Commodities under the equity method.
In 2018, we fully impaired our remaining equity method investment in RBS Sempra Commodities. In 2020, we recorded a charge of $100 million in Equity Earnings on Sempra’s Consolidated Statement of Operations for losses from our investment in RBS Sempra Commodities. In 2021, we reduced this charge by $50 million based on the favorable outcome of a settlement with HMRC and revised assumptions on the High Court of Justice case. We discuss matters related to RBS Sempra Commodities further in “Other Litigation” in Note 16.
SUMMARIZED FINANCIAL INFORMATION
We present summarized financial information below, aggregated for all other equity method investments (excluding Oncor Holdings and RBS Sempra Commodities) for the periods in which we were invested in the entities. The amounts below represent the results of operations and aggregate financial position of 100% of each of Sempra’s other equity method investments.
(1) In March 2021, Sempra Infrastructure completed the acquisition of the remaining 50% equity interest in ESJ and ESJ became a wholly owned, consolidated subsidiary.
(2) On April 22, 2019, Sempra Renewables sold its remaining wind assets and investments. As of April 22, 2019, these wind assets and investments are no longer equity method investments.
(3) Except for our investments in Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.
NOTE 7. DEBT AND CREDIT FACILITIES
SHORT-TERM DEBT
Committed Lines of Credit
At December 31, 2021, Sempra had an aggregate capacity of $9.5 billion under seven primary committed lines of credit, which provide liquidity and support our commercial paper programs. Because our commercial paper programs are supported by these lines of credit, we reflect the amount of commercial paper outstanding, before reductions of any unamortized discounts, and any letters of credit outstanding as a reduction to the available unused credit capacity.
The principal terms of the Sempra, SDG&E and SoCalGas primary committed lines of credit reflected in the table above include the following:
▪Each facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in any facility.
▪Sempra’s $1.3 billion facility and SDG&E’s and SoCalGas’ facilities provide for the issuance of $200 million, $100 million and $100 million, respectively, of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra, SDG&E and SoCalGas each have the right to increase its letter of credit commitment up to $500 million, $250 million and $250 million, respectively.
▪Borrowings bear interest at a benchmark rate plus a margin that varies with the borrower’s credit rating.
▪Each borrower must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) of no more than 65% at the end of each quarter. At December 31, 2021, each entity was in compliance with this ratio under its respective credit facility.
In November 2021, SI Partners entered into a three-year $1.0 billion credit facility. The principal terms of the SI Partners’ line of credit reflected in the table above include the following:
▪A syndication of 12 lenders each having an 8.33% share in the facility.
▪The facility provides for issuance of $200 million of letters of credit.
▪The facility includes a $100 million swingline loan sub-limit, whereby any outstanding amounts would reduce available unused credit. No swingline loan borrowings were outstanding at December 31, 2021.
▪Borrowings are issued in U.S. dollars and letters of credit can be issued in U.S. dollars or Mexican pesos.
▪Borrowings bear interest at a benchmark rate plus a margin that varies with SI Partners’ credit rating.
▪SI Partners must maintain a ratio of consolidated adjusted net indebtedness to consolidated earnings before interest, taxes, depreciation and amortization (as defined in its credit facility) of no more than 5.25 to 1.00 as of the end of each quarter. At December 31, 2021, SI Partners was in compliance with this ratio.
IEnova has two revolving credit facilities. The principal terms of IEnova’s lines of credit reflected in the table above include the following:
▪The $350 million revolving credit facility, which was amended in September 2021 to increase the amount available under the facility from $280 million to $350 million and extend the expiration date from September 2021 to September 2023, has a single lender and borrowings bear interest at a per annum rate equal to 3-month LIBOR plus 54 bps.
▪The $1.5 billion revolving credit facility has a syndicate of 10 lenders and borrowings bear interest at a per annum rate equal to 3-month LIBOR plus 80 bps.
▪Borrowings can be issued in U.S. dollars only.
Uncommitted Lines of Credit
In addition to our committed lines of credit, Sempra Infrastructure’s foreign operations in Mexico have uncommitted lines of credit with an aggregate capacity of $470 million at December 31, 2021, which are generally used for working capital requirements. We reflect amounts outstanding before reductions of any unamortized discounts.
(1) Borrowings bear interest at a per annum rate equal to 3-month LIBOR plus 10 bps.
(2) Outstanding amounts were borrowed in Mexican pesos and bear interest at a variable rate based on the 28-day Interbank Equilibrium Interest Rate plus 105 bps. Borrowings made in U.S. dollars bear interest at a variable rate based on the 1-month or 3-month LIBOR plus 105 bps.
(3) Borrowings bear interest at a per annum rate equal to between 1-month and 6-month LIBOR plus 52 bps.
(4) Borrowings made in Mexican pesos bear interest at a variable rate based on the 28-day Interbank Equilibrium Interest Rate plus an applicable margin. Borrowings made in U.S. dollars bear interest at a variable rate based on 1-month LIBOR plus an applicable margin. The applicable margin is determined on the date of borrowing.
Uncommitted Letters of Credit
Outside of our domestic and foreign credit facilities, we have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At December 31, 2021, there was approximately $682 million in standby letters of credit outstanding under these agreements.
Term Loan
In June 2021, SDG&E entered into a $375 million, 364-day term loan with a maturity date of June 27, 2022. At December 31, 2021, $375 million, net of negligible issuance costs, was outstanding under the term loan. The borrowing bears interest at benchmark rates plus 62.5 bps. The term loan provides SDG&E with additional liquidity outside of its line of credit.
Weighted-Average Interest Rates
The weighted-average interest rates on the total short-term debt at December 31 were as follows:
LONG-TERM DEBT
The following tables show the detail and maturities of long-term debt outstanding:
(1) Callable long-term debt not subject to make-whole provisions.
(2) Debt is not callable.
(1) Excludes finance lease obligations, discounts, and debt issuance costs.
Various long-term obligations totaling $9.1 billion at Sempra at December 31, 2021 are unsecured. This includes unsecured long-term obligations totaling $309 million at SoCalGas. SDG&E does not have unsecured long-term obligations at December 31, 2021.
Callable Long-Term Debt
At the option of Sempra, SDG&E and SoCalGas, certain debt at December 31, 2021 is callable subject to premiums:
First Mortgage Bonds
SDG&E and SoCalGas issue first mortgage bonds secured by liens on their respective utility plant assets. SDG&E and SoCalGas may issue additional first mortgage bonds if in compliance with the provisions of their bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $7.3 billion at SDG&E and $1.9 billion at SoCalGas at December 31, 2021.
SDG&E
In August 2021, SDG&E issued $750 million of 2.95% green first mortgage bonds maturing in 2051 and received proceeds of $737 million, net of debt discount, underwriting discounts and debt issuance costs of $13 million. SDG&E intends to use the net proceeds to finance or refinance eligible projects that fall into one or more of the following categories: climate change adaptation, clean energy solutions and clean transportation.
Other Long-Term Debt
Sempra
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 November 2021, we issued $1.0 billion of 4.125% fixed-to-fixed reset rate junior subordinated notes maturing on April 1, 2052. Interest on the notes accrues from and including November 19, 2021 and is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on April 1, 2022. The notes will bear interest (i) from and including November 19, 2021 to, but excluding, April 1, 2027 at the rate of 4.125% per annum and (ii) from and including April 1, 2027, during each subsequent five-year period beginning on April 1 of every fifth year, at a rate per annum equal to the Five-year U.S. Treasury Rate (as defined in the notes) as of the day falling two business days before the first day of such five-year period plus a spread of 2.868%, to be reset on April 1 of every fifth year beginning in 2027. We received proceeds of $988 million (net of underwriting discounts and debt issuance costs of $12 million). We used the proceeds from the offering to repay a portion of the aggregate principal amount of the $2.35 billion of senior unsecured notes that we discuss above. We may redeem some or all of the notes before their maturity, as follows:
▪in whole or from time to time in part, on any day during any period from and including the January 1 immediately preceding an interest rate reset date through and including such reset date at a redemption price in cash equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest on the notes to be redeemed to, but excluding, the redemption date;
▪in whole but not in part, at any time following the occurrence and during the continuance of a tax event (as defined in the notes) at a redemption price in cash equal to 100% of the principal amount of the notes, plus accrued and unpaid interest on the notes to, but excluding, the redemption date; and
▪in whole but not in part, at any time following the occurrence and during the continuance of a rating agency event (as defined in the notes) at a redemption price in cash equal to 102% of the principal amount of the notes, plus accrued and unpaid interest on the notes to, but excluding, the redemption date.
The notes are unsecured obligations and rank junior and subordinate in right of payment to our existing and future senior indebtedness. The notes rank equally in right of payment with our existing 5.75% junior subordinated notes due 2079 and with any future unsecured indebtedness that we may incur if the terms of such indebtedness provide that it ranks equally with the notes in right of payment. The notes are effectively subordinated in right of payment to any secured indebtedness we have incurred or may incur and to all existing and future indebtedness and other liabilities of our subsidiaries.
SDG&E
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.
Sempra Infrastructure
SI Partners. On January 11, 2022, SI Partners completed a private offering of $400 million in aggregate principal of 3.25% senior notes due January 15, 2032 to “qualified institutional buyers” as defined in Rule 144A under the Securities Act of 1933, as amended (the Securities Act), and non-U.S. persons outside the U.S. under Regulation S under the Securities Act. 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. The notes are senior unsecured obligations that rank equally with all of SI Partners’ existing and future outstanding unsecured senior indebtedness. Sempra Infrastructure received proceeds of $390 million (net of debt discount, underwriting discounts and debt issuance costs of $10 million). Sempra Infrastructure intends to use the net proceeds for general corporate purposes, which may include the repayment of certain indebtedness of its subsidiaries.
At any time prior to October 15, 2031, SI Partners may redeem some or all of the notes by paying the greater of (i) 100% of the principal amount of the notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest thereon (exclusive of interest accrued to, but excluding, the date of redemption) as if redeemed on October 15, 2031 discounted to the redemption date on a semi-annual basis at the U.S. Treasury rate plus 25 bps and, in each case, accrued and unpaid interest to, but excluding, the date of redemption. At any time beginning on October 15, 2031, SI Partners may redeem some or all of the notes by paying 100% of the principal amount of the notes to be redeemed, plus, in each case, accrued and unpaid interest to, but excluding, the date of redemption. Upon the occurrence of specific kinds of change of control events that result in a downgrade of SI Partners’ credit ratings, holders of the notes would have the right to require SI Partners to offer to purchase some or all of the notes at 101% of the then outstanding principal amount thereof, plus, in each case, accrued and unpaid interest to, but excluding, the date of redemption.
ECA LNG Phase 1. In December 2020, ECA LNG Phase 1 entered into a five-year loan agreement with a syndicate of nine banks for an aggregate principal amount of up to $1.6 billion. Proceeds from the loan are being used to finance the cost of development and construction of a one-train natural gas liquefaction export facility with a name-plate capacity of 3.25 Mtpa and initial offtake capacity of approximately 2.5 Mtpa. The loan matures in December 2025 and bears interest at a weighted-average blended rate of 2.70% plus a benchmark interest rate per annum equal to (a) the LIBOR for such interest period divided by (b) one minus the Eurodollar Reserve Percentage; provided that in no event shall the benchmark at any time be less than 0% per annum. ECA LNG Phase 1 may elect for each calendar quarter (i) three successive interest periods of one month or (ii) a single interest period of three months. Sempra and TotalEnergies SE have provided guarantees for repayment of the loans plus accrued and unpaid interest based on their proportionate ownership interest in ECA LNG Phase 1 of 83.4% and 16.6%, respectively. The effective interest rate of the loan is based on the interest payments made to external lenders and guarantee payments made to TotalEnergies SE as a guarantor. At December 31, 2021 and 2020, $341 million and $17 million, respectively, was outstanding under the loan agreement, with a weighted-average interest rate of 2.93% and 2.82%, respectively.
ESJ. As we discuss in Note 5, through its acquisition of the remaining 50% of ESJ, Sempra Infrastructure assumed a $177 million (net of $6 million in unamortized debt issuance costs) variable rate loan payable to a syndicate of five lenders that matures in June 2033. To moderate exposure to interest rate and associated cash flow variability, ESJ entered into floating-to-fixed rate swaps for 90% of the principal balance, resulting in a fixed rate of 6.13%. The remaining 10% of the principal balance bore interest at 6-month LIBOR plus a margin of 2.63% with an increase of 25 bps every four years. On October 8, 2021, Sempra Infrastructure used proceeds from borrowings against IEnova’s committed and uncommitted lines of credit to fully repay the $175 million of outstanding principal plus accrued and unpaid interest on the ESJ loan prior to its scheduled maturity in 2033, and recognized $18 million ($10 million after tax and NCI) in charges associated with hedge termination costs and a write-off of unamortized debt issuance costs.
Ventika. On October 13, 2021, Sempra Infrastructure used proceeds from borrowings against IEnova’s committed and uncommitted lines of credit to fully repay $375 million of outstanding principal plus accrued and unpaid interest on the Ventika fixed- and variable-rate loans prior to scheduled maturity dates through 2032, and recognized $36 million ($20 million after tax and NCI) in charges associated with hedge termination costs and a write-off of unamortized debt issuance costs.
NOTE 8. INCOME TAXES
We provide our calculations of ETRs in the following table.
(1) We discuss how we recognize equity earnings in Note 6.
For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the ETR. The following items are subject to flow-through treatment:
▪repairs expenditures related to a certain portion of utility plant fixed assets
▪the equity portion of AFUDC, which is non-taxable
▪a portion of the cost of removal of utility plant assets
▪utility self-developed software expenditures
▪depreciation on a certain portion of utility plant assets
▪state income taxes
The AFUDC related to equity recorded for regulated construction projects at Sempra Infrastructure has similar flow-through treatment.
We record income tax (expense) benefit from the transactional effects of foreign currency and inflation. Through the first quarter of 2021, such effects are offset by net gains (losses) from foreign currency derivatives that were hedging Sempra Infrastructure’s exposure to movements in the Mexican peso from its controlling interest in IEnova.
We present in the table below reconciliations of net U.S. statutory federal income tax rates to our ETRs.
(1) Related to operations in Mexico.
(2) Due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of appreciation (depreciation) of the Mexican peso. We also recognize gains (losses) in Other Income (Expense), Net, on the Consolidated Statements of Operations from foreign currency derivatives that are partially hedging Sempra Infrastructure’s exposure to movements in the Mexican peso from its controlling interest in IEnova.
In January 2019, our board of directors approved a plan to sell our South American businesses and we completed the sales in the second quarter of 2020, as we discuss in Note 5. Prior to this decision, our repatriation estimate excluded post-2017 earnings and other basis differences related to our South American businesses. Because of our decision to sell our South American businesses,
we no longer assert indefinite reinvestment of these basis differences. Accordingly, we recorded the following income tax impacts from changes in outside basis differences in our discontinued operations in South America:
▪$89 million income tax benefit in 2019 primarily related to outside basis differences existing as of the January 25, 2019 approval of our plan to sell our South American 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 January 25, 2019.
We expect to repatriate approximately $1.8 billion of foreign undistributed earnings in the foreseeable future, and have accrued $59 million of U.S. state deferred income tax liability at December 31, 2021 for repatriations that we expect will begin in 2022 as cash is generated. We repatriated approximately $4.7 billion and $254 million to the U.S. in 2020 and 2019, respectively.
We have not recorded deferred income taxes with respect to remaining basis differences of approximately $600 million between financial statement and income tax investment amounts in our non-U.S. subsidiaries because we consider them to be indefinitely reinvested as of December 31, 2021. However, the sale of NCI in SI Partners to ADIA, which we discuss in Note 1, would affect our indefinite reinvestment assertion. The remaining basis differences are calculated pursuant to U.S. federal tax law, which may differ from tax law in California and foreign jurisdictions. It is currently not practicable to determine the hypothetical amount of tax that might be payable if the underlying basis differences were realized.
The remeasurement of deferred income tax balances at SDG&E and SoCalGas in December 2017, as a result of the TCJA, resulted in excess deferred income taxes that previously had been collected from ratepayers at the higher rate. In a January 2019 decision, the CPUC directed certain excess deferred income tax balances generated by activities outside of ratemaking be allocated to shareholders rather than ratepayers. As a result, in 2019, SDG&E and SoCalGas recorded income tax benefits of $31 million and $38 million, respectively, from the release of a portion of the regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances.
The table below presents the geographic components of pretax income.
(1) See the Income Tax Expense (Benefit) and Effective Income Tax Rates table above for the calculation of pretax income.
U.S. pretax income was lower in 2021 compared to 2020 and 2019 primarily due to the 2021 charges at SoCalGas related to civil litigation pertaining to the Leak, which we describe in Note 16.
The components of income tax expense are as follows.
The tables below present the components of deferred income taxes:
(1) In addition to the financial over tax basis differences in fixed assets, the amount also includes financial over tax basis differences in various interests in partnerships and certain subsidiaries.
(2) At December 31, 2021, 2020, and 2019, includes $151, $136, and $155, respectively, recorded as a noncurrent asset and $3,477, $2,871, and $2,577, respectively, recorded as a noncurrent liability on the Consolidated Balance Sheets.
The following table summarizes our unused NOLs and tax credit carryforwards.
(1) We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not-basis.
(2) We have not recorded deferred income tax benefits on a portion of these NOLs and tax credits because we currently believe they will not be realized on a more-likely-than-not-basis, as discussed below.
A valuation allowance is recorded when, based on more-likely-than-not criteria, negative evidence outweighs positive evidence with regard to our ability to realize a deferred income tax asset in the future. Of the valuation allowances recorded to date, the negative evidence outweighs the positive evidence primarily due to cumulative pretax losses in various U.S. state and non-U.S. jurisdictions resulting in deferred income tax assets that we currently do not believe will be realized on a more-likely-than-not basis. The following table provides the valuation allowances that we recorded against a portion of our total deferred income tax assets shown above in the “Deferred Income Taxes - Sempra” table.
Following is a reconciliation of the changes in unrecognized income tax benefits and the potential effect on our ETR for the years ended December 31:
(1) Includes temporary book and tax differences that are treated as flow-through for ratemaking purposes, as discussed above.
It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following:
Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in Income Tax Expense on the Consolidated Statements of Operations. Sempra accrued negligible amounts at December 31, 2021 and 2020 and $1 million for interest expense and penalties at December 31, 2019 on the Consolidated Balance Sheets, and recorded negligible amounts for interest and penalties in the Consolidated Statements of Operations for all periods presented. SDG&E and SoCalGas
each accrued negligible amounts for interest expense and penalties at December 31, 2021, 2020, and 2019 on the Consolidated Balance Sheets, and recorded negligible amounts of interest expense and penalties in the Consolidated Statements of Operations for all periods presented.
INCOME TAX AUDITS
Sempra is subject to U.S. federal income tax as well as income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2017. We are subject to examination by major state tax jurisdictions for tax years after 2012. Certain major non-U.S. income tax returns for tax years 2013 through the present are open to examination. We are also open to examination for non-U.S. income tax returns related to our prior interest in our commodities business, which we divested in 2010, for years 2009 and 2010.
SDG&E and SoCalGas are subject to U.S. federal income tax and state income tax. They remain subject to examination for U.S. federal tax years after 2017 and state tax years after 2012.
In addition, Sempra has filed protests to contest proposed state audit adjustments for tax years 2009 through 2012. The pre-2013 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years.
NOTE 9. EMPLOYEE BENEFIT PLANS
For our employee benefit plans, we:
▪recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the balance sheet;
▪measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year; and
▪recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.
The detailed information presented below covers the employee benefit plans of primarily Sempra and its consolidated subsidiaries.
Sempra has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees, including a member of the Sempra board of directors who was a participant in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.
IEnova has an unfunded noncontributory defined benefit plan covering all employees that provides defined benefits to retirees based on date of hire, years of service and final average earnings.
Sempra also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits.
Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. We review these assumptions on an annual basis and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans.
RABBI TRUST
In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $567 million, $512 million and $488 million at December 31, 2021, 2020 and 2019, respectively.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Benefit Plan Amendments Affecting 2019
In 2019, certain executive participants in a company nonqualified pension plan became eligible in this same plan for Supplemental Executive Retirement Plan benefits. This was treated as a plan amendment and increased the recorded pension liability by $5 million at Sempra, $3 million at SDG&E and $2 million at SoCalGas in 2019.
Oncor
In 2021, 2020 and 2019, we had $7 million, $11 million and $27 million, respectively, in AOCI representing an actuarial loss related to Oncor’s pension plans.
Benefit Obligations and Assets
The following three tables provide a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2021, 2020 and 2019, and a statement of the funded status at December 31, 2021, 2020 and 2019:
Actuarial losses (gains) fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and Other Postretirement Benefit Plans” and updates to census data. In 2021, 2020 and 2019, the Society of Actuaries released updated mortality improvement projection scales, reflecting changes to projected observed longevity improvements in its mortality tables. We have incorporated these assumptions, adjusted for the Sempra companies’ actual mortality experience, in our calculations for each of those years.
▪Actuarial gains in pension plans at Sempra in 2021 were driven primarily by an increase in discount rates at SoCalGas, SDG&E and Sempra and updated census data at SoCalGas. These actuarial gains were partially offset by actuarial losses at SDG&E, SoCalGas and Sempra due to an increase in the interest crediting rate for the cash balance plans, at SDG&E and Sempra due to updated census data and at SoCalGas due to a decrease in the conversion rate used to determine lump-sum distributions.
▪Actuarial gains in PBOP plans at Sempra in 2021 were driven primarily by an increase in discount rates at SoCalGas, SDG&E and Sempra, updated census data at SoCalGas and a reduction in the 2022 expected health care costs at SoCalGas.
Net Assets and Liabilities
The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic benefit cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year.
The 10% corridor accounting method is used at Sempra, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The asset smoothing and 10% corridor accounting methods help mitigate volatility of net periodic benefit costs from year to year.
Defined benefit pension and other postretirement plans with an aggregated overfunded status are recognized as an asset and with an aggregated underfunded status are recognized as a liability; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. SDG&E and SoCalGas record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on decisions by regulatory agencies.
SDG&E and SoCalGas record annual pension and other postretirement net periodic benefit costs equal to the contributions to their qualified plans as authorized by the CPUC. The annual contributions to the pension plans are the greater of:
▪a minimum required funding amount as required by the IRS;
▪the amount required to maintain an 85% Adjusted Funding Target Attainment Percentage as defined by the Pension Protection Act of 2006, as amended; or
▪beginning January 1, 2019 and for the duration of the 2019 GRC cycle, a fixed amount equal to the estimated annual service cost as defined by U.S. GAAP plus one year of a 14-year amortization of the unfunded projected benefit obligation of the pension plan as of January 1, 2019, and limited to an annual amount that keeps the fair value of the pension plan assets from exceeding 110% of the pension benefit obligation of the plan.
The annual contributions to PBOP plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and PBOP plans. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans for SDG&E and SoCalGas are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.
The net (liability) asset is included in the following categories on the Consolidated Balance Sheets at December 31:
Amounts recorded in AOCI at December 31, net of income tax effects and amounts recorded as regulatory assets, are as follows:
(1) Includes discontinued operations in 2020 and 2019.
Sempra, SDG&E and SoCalGas each have a funded pension plan. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31:
We also have unfunded pension plans at Sempra, SDG&E, SoCalGas and IEnova. The following table shows the obligations of unfunded pension plans at December 31:
Sempra, SDG&E and SoCalGas each have a funded other postretirement benefit plan. At December 31, 2021, the assets for SDG&E’s and SoCalGas’ other postretirement benefit plans exceeded the plans’ obligations. The following table shows the obligations of funded other postretirement benefit plans with accumulated postretirement benefit obligations in excess of plan assets at December 31:
We also have unfunded other postretirement benefit plans at Sempra. The following table shows the obligations of unfunded other postretirement benefit plans at December 31:
Net Periodic Benefit Cost
The following tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31:
(1) Includes discontinued operations in 2020 and 2019.
Assumptions for Pension and Other Postretirement Benefit Plans
Benefit Obligation and Net Periodic Benefit Cost
Except for the IEnova plans, we develop the discount rate assumptions using a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality corporate bonds that generate sufficient cash flows to provide for projected benefit payments of the plan. The selected bond portfolio is derived from a universe of corporate bonds with a Bloomberg Composite of AA or higher. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plans’ projected benefit payments discounted at this rate with the market value of the bonds selected.
We develop the discount rate assumptions for the plans at IEnova by constructing a synthetic government zero coupon bond yield curve from the available market data, based on duration matching, and we add a risk spread to allow for the yields of high-quality corporate bonds. Such method is required when there is no deep market for high quality corporate bonds.
Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.
Interest crediting rate is based on an average 30-year Treasury bond from the month of November of the preceding year.
We amortize prior service cost using straight line amortization over average future service (or average expected lifetime for plans where participants are substantially inactive employees), which is an alternative method allowed under U.S. GAAP.
The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:
(1) Interest crediting rate for pension benefits applies only to funded cash balance plans.
(2) Interest crediting rate for other postretirement benefits applies only to interest bearing health retirement accounts at SDG&E and SoCalGas.
(1) Interest crediting rate for pension benefits applies only to funded cash balance plans.
(2) Interest crediting rate for other postretirement benefits applies only to interest bearing health retirement accounts at SDG&E and SoCalGas.
Health Care Cost Trend Rates
Assumed health care cost trend rates have a significant effect on the amounts that Sempra, SDG&E and SoCalGas report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans:
Plan Assets
Investment Allocation Strategy for Sempra’s Pension Master Trust
Sempra’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. We maintain additional trusts, as we discuss below, for certain of SDGE’s and SoCalGas’ PBOP plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra.
The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. We assess the portfolio performance by comparing actual returns with relevant benchmarks. Currently, the pension plans’ target asset allocations are:
▪31% domestic equity
▪21% international equity
▪21% long credit
▪10% diversified real assets
▪10% return-seeking credit
▪5% ultra-long duration government securities
▪2% other diversifying assets
The asset allocation of the plans is reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis. When evaluating strategic asset allocations, the Committees consider many variables, including:
▪long-term cost
▪variability and level of contributions
▪funded status
▪a range of expected outcomes over varying confidence levels
This allocation results in a 74% target allocation to return-seeking assets and a 26% target allocation to risk-mitigating assets. We maintain asset allocations at strategic levels with reasonable bands of variance.
In accordance with the Sempra pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.
Rate of Return Assumption
The expected return on assets in our pension and PBOP plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date. We arrive at a 6.75% expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between 4% and 12% on return-seeking assets and between 1% and 4% for risk-mitigating assets. Certain trusts that hold assets for the SDG&E other postretirement benefit plan are subject to taxation, which impacts the expected after-tax return on assets in the plan.
Concentration of Risk
Plan assets are diversified across global equity and bond markets, and concentration of risk in any one economic, industry, maturity or geographic sector is limited.
Investment Strategy for SDG&E’s and SoCalGas’ Other Postretirement Benefit Plans
SDG&E’s and SoCalGas’ PBOP plans are funded by cash contributions from SDG&E and SoCalGas and their current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association trusts. Certain assets of SDG&E’s and SoCalGas’ PBOP plans are held in the pension master trust, which invests a portion of the assets in completion portfolios that aim to reduce interest rate risk, thereby resulting in an overall target allocation of 38% to return-seeking assets and 62% to risk-mitigating assets for these well-funded plans. Certain of SoCalGas’ PBOP plans are held in a Voluntary Employee Benefit Association trust that also utilizes a completion portfolio, resulting in a target allocation of 30% to return-seeking assets and 70% to risk-mitigating assets. SDG&E’s and SoCalGas’ assets held in other Voluntary Employee Beneficiary Association trusts are invested in accordance with a de-risking glidepath that reduces the assets’ exposure to risk as the trusts become better funded. These specific allocations are periodically reviewed to help ensure that plan assets are best positioned to meet plan obligations.
Fair Value of Pension and Other Postretirement Benefit Plan Assets
We classify the investments in Sempra’s pension master trust and the trusts for SDG&E’s and SoCalGas’ PBOP plans based on the fair value hierarchy, except for certain investments measured at NAV.
The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.
Equity Securities - Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.
Registered Investment Companies - Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified within Level 1 of the fair value hierarchy. Other investments are valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.
Fixed Income Securities - Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.
Common/Collective Trusts - Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.
Venture Capital Funds and Real Estate Funds - These funds consist of investments in venture capital funds and real estate funds that are held by limited partnerships or similar private entities following various investment strategies. The value is determined based on the NAV of our proportionate ownership interest in the entity.
Derivative Financial Instruments - Futures contracts that are publicly traded in active markets are valued at closing prices as of the last business day of the year. Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index futures contracts are valued at the last sales price quoted on the exchange on which they primarily trade.
While management believes the valuation methods described above are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
We provide more discussion of fair value measurements in Notes 1 and 12. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis.
SDG&E and SoCalGas each hold a proportionate share of investment assets in the pension master trust at Sempra. The fair values of our pension plan assets by asset category are as follows:
The fair values by asset category of the PBOP plan assets held in the pension master trust and in the additional trusts for SoCalGas’ PBOP plans and SDG&E’s PBOP plan trusts are as follows:
Future Payments
We expect to contribute the following amounts to our pension and PBOP plans in 2022:
The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.
SAVINGS PLANS
Sempra, SDG&E and SoCalGas offer trusteed savings plans to all employees. Employee participation, employee contributions and employer matching contributions are subject to the provisions of the respective plans, and for employee contributions, limits imposed by the respective governmental authorities.
Employer contributions to the savings plans were as follows:
The market value of Sempra common stock held by the savings plans was $1.0 billion, $1.1 billion and $1.3 billion at December 31, 2021, 2020 and 2019, respectively.
NOTE 10. SHARE-BASED COMPENSATION
SEMPRA EQUITY COMPENSATION PLANS
Sempra has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra. The plans permit a wide variety of share-based awards, including:
▪nonqualified stock options
▪incentive stock options
▪restricted stock awards
▪restricted stock units
▪stock appreciation rights
▪performance awards
▪stock payments
▪dividend equivalents
Eligible employees, including those from SDG&E and SoCalGas, participate in Sempra’s share-based compensation plans as a component of their compensation package.
In the three years ended December 31, 2021, Sempra had the following types of equity awards outstanding:
▪Nonqualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a three-year period and expire 10 years from the date of grant. Unvested option awards are subject to forfeiture following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.
▪Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra common stock at the end of three-year performance periods based on Sempra’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index (excluding water companies) and the S&P 500 Index. We use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies (excluding water companies) to develop our targets for awards that vest based on EPS growth. These RSU awards are subject to forfeiture prior to vesting following a termination of employment, except where the retirement criteria under such awards have been met and subject to certain other exceptions described below.
◦Up to an additional 100% of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.
◦For awards granted in 2016 and certain awards granted in 2017 and 2018 that vest based on Sempra’s total return to shareholders, a modifier adds 20% to the award’s payout (as initially calculated based on total return to shareholders relative to that of specified market indices) for total shareholder return performance in the top quartile relative to historical benchmark data for Sempra and reduces the award’s payout by 20% for performance in the bottom quartile. However, in no event will more than an additional 100% of the granted RSUs be issued. If performance falls within the second or third quartiles, the modifier is not triggered, and the payout is based solely on total return to shareholders relative to that of specified market indices.
If Sempra’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis.
▪Other Performance-Based Restricted Stock Units: RSUs were granted in 2015 in connection with the creation of Cameron LNG JV. The 2015 awards vested in 2019 as both of the following were achieved: (a) the Compensation and Talent Committee of Sempra’s board of directors determined that Sempra achieved positive cumulative net income for fiscal years 2015 through 2017 and (b) Cameron LNG JV commenced commercial operations of the first train.
▪Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest ratably over three-year service periods (for awards granted after 2018), or at the end of three-year (for awards granted during 2016 through 2018) or four-year service periods (for awards granted prior to 2015). These awards are subject to earlier forfeiture upon termination of employment, subject to certain exceptions described below.
For awards that would otherwise be forfeited upon termination of employment, the Compensation and Talent Development Committee of Sempra’s board of directors may waive the forfeiture requirement and, with respect to options and service-based RSUs, may accelerate vesting. Awards are also subject to accelerated vesting upon a change in control under the applicable LTIP, in accordance with severance pay agreements or to the extent otherwise required by the terms of the applicable award. Dividend equivalents on shares subject to RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSUs to which the dividends relate.
SHARE-BASED AWARDS AND COMPENSATION EXPENSE
At December 31, 2021, 5,986,241 common shares were authorized and available for future grants of share-based awards. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.
We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for nonqualified stock options and RSUs on a straight-line basis over
the requisite service period of the award, which is generally three or four years. However, for awards granted to retirement-eligible participants, the expense is recognized over the initial year in which the award was granted as the award requires service through the end of the year in which it was granted. For awards granted to participants who become eligible for retirement during the requisite service period, the expense is recognized over the period between the date of grant and the later of the end of the year in which the award was granted or the date the participant first becomes eligible for retirement. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards. We recognize in earnings the tax benefits (or deficiencies) resulting from tax deductions that are in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments.
Sempra subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra plans’ corporate staff costs. Total share-based compensation expense for all of Sempra’s share-based awards was comprised as follows:
(1) Includes activity of awards issued from the IEnova 2013 LTIP, which settled in cash upon vesting based on the price of IEnova’s common stock.
SEMPRA NONQUALIFIED STOCK OPTIONS
We use a Black-Scholes option-pricing model to estimate the fair value of each nonqualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on a blend of the historical and implied volatility of Sempra’s common stock price. The average expected term for options is based on the vesting schedule, contractual term of the option, expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected term estimated at the date of the grant. In 2021, 2020 and 2019, Sempra’s board of directors granted 222,620, 154,860 and 261,075 nonqualified stock options, respectively, that are exercisable over a three-year period. The weighted-average per-share fair value for options granted was $19.07, $19.76 and $13.20 in 2021, 2020 and 2019, respectively. To calculate this fair value, we used the Black-Scholes model with the following weighted-average assumptions:
The following table shows a summary of nonqualified stock options at December 31, 2021 and activity for the year then ended:
The aggregate intrinsic value at December 31, 2021 is the total of the difference between Sempra’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for nonqualified stock options exercised in the last three years was:
▪$1.4 million in 2021
▪$0.4 million in 2020
▪$4 million in 2019
We expect a negligible amount of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2021 to be recognized over a weighted-average period of 1.1 years. The weighted-average per-share fair values for nonqualified stock options granted in 2020 and 2019 was $149.12 and $106.76, respectively.
We received cash of $5 million, a negligible amount and $3 million from stock option exercises in 2021, 2020 and 2019, respectively.
SEMPRA RESTRICTED STOCK UNITS
We use a Monte-Carlo simulation model to estimate the fair value of our RSUs that vest based on Sempra’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra and its peer group companies. The valuation also is affected by the risk-free rates of return and a number of other variables. Below are key assumptions for RSUs granted in the last three years:
The following table shows a summary of RSUs at December 31, 2021 and activity for the year then ended:
(1) Each RSU represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based RSUs, up to an additional 100% of the shares represented by the RSUs may be issued if Sempra exceeds target performance conditions.
In 2021, 2020 and 2019, the total fair value of RSU shares vested during the year was $57 million, $70 million and $36 million, respectively.
We expect $17 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2021 to be recognized over a weighted-average period of 1.5 years. The weighted-average per-share fair values for performance-based RSUs granted were $155.62 and $113.54 in 2020 and 2019, respectively. The weighted-average per-share fair values for service-based RSUs granted were $138.91 and $112.50 in 2020 and 2019, respectively.
NOTE 11. DERIVATIVE FINANCIAL INSTRUMENTS
We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that could cause our asset values to fall or our liabilities to increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.
In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.
In all other cases, we record derivatives at fair value on the Consolidated Balance Sheets. We may have derivatives that are (1) cash flow hedges, (2) fair value hedges, or (3) undesignated. Depending on the applicability of hedge accounting and, for SDG&E and SoCalGas and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in OCI (cash flow hedges), on the balance sheet (regulatory offsets), or recognized in earnings (fair value hedges and undesignated derivatives not subject to rate recovery). We classify cash flows from the principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt and hedge termination costs on interest rate swaps as financing activities and settlements of other derivative instruments as operating activities on the Consolidated Statements of Cash Flows.
HEDGE ACCOUNTING
We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria.
ENERGY DERIVATIVES
Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:
▪SDG&E and SoCalGas use natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed-price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.
▪SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.
▪Sempra Infrastructure may use natural gas and electricity derivatives, as appropriate, in an effort to optimize the earnings of their assets which support the following businesses: LNG, natural gas transportation and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues on the Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges.
▪From time to time, our various businesses, including SDG&E and SoCalGas, may use other energy derivatives to hedge exposures such as GHG allowances.
The following table summarizes net energy derivative volumes.
INTEREST RATE DERIVATIVES
We are exposed to interest rates primarily as a result of our current and expected use of financing. SDG&E and SoCalGas, as well as Sempra and its other subsidiaries and JVs, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.
The following table presents the net notional amounts of our interest rate derivatives, excluding those in our equity method investments, at December 31:
FOREIGN CURRENCY DERIVATIVES
We utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries and JVs. These cash flow hedges exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. From time to time, Sempra Infrastructure and its JVs may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar.
We are also exposed to exchange rate movements at our Mexican subsidiaries and JVs, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which 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. We may utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts; however, we generally do not hedge our deferred income tax assets and liabilities or for 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, respectively.
The following table presents the net notional amounts of our foreign currency derivatives, excluding those in our equity method investments, at December 31.
FINANCIAL STATEMENT PRESENTATION
The Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets, including the amount of cash collateral receivables that were not offset because the cash collateral was in excess of liability positions.
(1) Normal purchase contracts previously measured at fair value are excluded.
(1) Normal purchase contracts previously measured at fair value are excluded.
(1) Normal purchase contracts previously measured at fair value are excluded.
The following table includes the effects of derivative instruments designated as cash flow hedges on the Consolidated Statements of Operations and in OCI and AOCI.
(1) Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. In August 2019, OMEC LLC paid in full its variable-rate loan and terminated its interest rate swaps.
(2) Equity earnings at our foreign equity method investees are recognized after tax.
For Sempra, we expect that net losses of $47 million, which are net of income tax benefit, that are currently recorded in AOCI (including $1 million in NCI) related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. SoCalGas expects that $1 million of losses, net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts mature.
For all forecasted transactions, the maximum remaining term over which we are hedging exposure to the variability of cash flows at December 31, 2021 is approximately 13 years for Sempra. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 18 years.
The following table summarizes the effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations.
CONTINGENT FEATURES
For Sempra, SDG&E and SoCalGas, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.
For Sempra, the total fair value of this group of derivative instruments in a liability position at December 31, 2021, 2020 and 2019 was $88 million, $16 million and $21 million, respectively. For SoCalGas, the total fair value of this group of derivative instruments in a liability position at December 31, 2021, 2020 and 2019 was $36 million, $6 million and $4 million, respectively. SDG&E did not have this group of derivative instruments in a liability position at December 31, 2021 2020 or 2019. At December 31, 2021, if the credit ratings of Sempra or SoCalGas were reduced below investment grade, $88 million and $36 million, respectively, of additional assets could be required to be posted as collateral for these derivative contracts.
For Sempra, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.
NOTE 12. FAIR VALUE MEASUREMENTS
RECURRING FAIR VALUE MEASURES
The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at December 31, 2021, 2020 and 2019. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair-valued assets and liabilities, and their placement within the fair value hierarchy.
The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 11 under “Financial Statement Presentation.”
The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).
Our financial assets and liabilities that were accounted for at fair value on a recurring basis in the tables below include the following (other than a $5 million investment at December 31, 2019 measured at NAV):
▪Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding accounts receivable and accounts payable. A third-party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).
▪For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market or income approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below in “Level 3 Information - SDG&E.”
▪Rabbi Trust investments include short-term investments that consist of money market and mutual funds that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1).
▪As we discuss in Note 6, in July 2020, Sempra entered into a Support Agreement for the benefit of CFIN. We measure the Support Agreement, which includes a guarantee obligation, a put option and a call option, net of related guarantee fees, at fair value on a recurring basis. We use a discounted cash flow model to value the Support Agreement, net of related guarantee fees. Because some of the inputs that are significant to the valuation are less observable, the Support Agreement is classified as Level 3, as we describe below in “Level 3 Information - Sempra Infrastructure.”
(1) Excludes receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(1) Excludes receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(1) Excludes receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(1) Excludes receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(1) Excludes receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Level 3 Information
SDG&E
The table below sets forth reconciliations of changes in the fair value of CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra and SDG&E.
(1) Excludes the effect of the contractual ability to settle contracts under master netting agreements.
Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.
CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, were in the following ranges for the years indicated below:
The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 11.
Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. The range and weighted-average price of these inputs at December 31 were as follows:
A significant increase (decrease) in market electricity forward prices would result in a significantly higher (lower) fair value. We summarize long-term, fixed-price electricity position volumes in Note 11.
Realized gains and losses associated with CRRs and long-term, fixed-price electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Because unrealized gains and losses are recorded as regulatory assets and liabilities, they do not affect earnings.
Sempra Infrastructure
The table below sets forth reconciliations of changes in the fair value of Sempra’s Support Agreement for the benefit of CFIN classified as Level 3 in the fair value hierarchy for Sempra.
(1) Net gains are included in Interest Income and net losses are included in Interest Expense on Sempra’s Consolidated Statements of Operations.
(2) Balances at December 31, 2021 and 2020 include $7 and $7, respectively, in Other Current Assets, offset by a negligible amount and $4, respectively, in Deferred Credits and Other on Sempra’s Consolidated Balance Sheets.
The fair value of the Support Agreement, net of related guarantee fees, is based on a discounted cash flow model using a probability of default and survival methodology. Our estimate of fair value considers inputs such as third-party default rates, credit ratings, recovery rates, and risk-adjusted discount rates, which may be readily observable, market corroborated or generally unobservable inputs. Because CFIN’s credit rating and related default and survival rates are unobservable inputs that are significant to the valuation, the Support Agreement, net of related guarantee fees, is classified as Level 3. We assigned CFIN an internally developed credit rating of A3 and relied on default rate data published by Moody’s to assign a probability of default. A hypothetical change in the credit rating up or down one notch could result in a significant change in the fair value of the Support Agreement.
Fair Value of Financial Instruments
The fair values of certain of our financial instruments (cash, accounts receivable, short-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Consolidated Balance Sheets.
(1) Before allowances for credit losses of $8 and excluding transaction costs of $5 at December 31, 2021.
(2) Before allowances for credit losses of $1 and $3 at December 31, 2021 and 2020, respectively. Includes $2 and $3 of accrued interest receivable at December 31, 2021 and 2020, respectively, in Due From Unconsolidated Affiliate - Current.
(3) Before reductions of unamortized discount and debt issuance costs of $260, $268 and $225 at December 31, 2021, 2020 and 2019, respectively, and excluding finance lease obligations of $1,335, $1,330 and $1,289 at December 31, 2021 and 2020 and 2019, respectively.
(4) Before reductions of unamortized discount and debt issuance costs of $61, $52 and $48 at December 31, 2021, 2020 and 2019, respectively, and excluding finance lease obligations of $1,274, $1,276 and $1,270 at December 31, 2021, 2020 and 2019, respectively.
(5) Before reductions of unamortized discount and debt issuance costs of $36, $40 and $34 at December 31, 2021, 2020 and 2019, respectively, and excluding finance lease obligations of $61, $54 and $19 at December 31, 2021, 2020 and 2019, respectively.
We provide the fair values for the securities held in the NDT related to SONGS in Note 15.
NOTE 13. PREFERRED STOCK
Sempra and SDG&E are authorized to issue up to 50 million and 45 million shares of preferred stock, respectively. At December 31, 2021, 2020 and 2019, SDG&E had no preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by each company’s board of directors at the time of issuance. We discuss SoCalGas preferred stock below.
SEMPRA MANDATORY CONVERTIBLE PREFERRED STOCK
On January 15, 2021, we converted 17,250,000 shares of series A preferred stock into 13,781,025 shares of our common stock based on a conversion rate of 0.7989 shares of our common stock for each issued and outstanding share of series A preferred stock. As a consequence, no shares of series A preferred stock were outstanding after January 15, 2021 and the 17,250,000 shares that were formerly series A preferred stock have returned to the status of authorized and unissued shares of preferred stock.
As of July 15, 2021, we had converted, pursuant to either early conversions at the election of the holder or the mandatory conversion of all outstanding shares, all 5,750,000 shares of series B preferred stock into an aggregate of 4,256,720 shares of our common stock and a nominal amount of cash in lieu of fractional share interests, based on a conversion rate of 0.7403 shares of our common stock for each issued and outstanding share of series B preferred stock. As a consequence, no shares of series B preferred stock were outstanding after July 15, 2021 and the 5,750,000 shares that were formerly series B preferred stock have returned to the status of authorized and unissued shares of preferred stock.
SEMPRA SERIES C PREFERRED STOCK
In June 2020, we issued 900,000 shares of our 4.875% fixed-rate reset cumulative redeemable perpetual preferred stock, series C (series C preferred stock) in a registered public offering at a price to the public of $1,000 per share and received net proceeds of $889 million after deducting the underwriting discount and equity issuance costs of $11 million. We used the net proceeds for working capital and other general corporate purposes, including the repayment of indebtedness.
Liquidation Preference
Each share of series C preferred stock has a liquidation preference of $1,000 plus any accumulated and unpaid dividends (whether or not declared) on such share.
Redemption at the Option of Sempra
The shares of series C preferred stock are perpetual and have no maturity date. However, we may, at our option, redeem the series C preferred stock in whole or in part, from time to time, on any day during the period from and including the July 15 immediately preceding October 15, 2025 and October 15 of every fifth year after 2025 through and including such October 15 at a redemption price in cash equal to $1,000 per share. Additionally, in the event that a credit rating agency then publishing a rating for us makes certain amendments, clarifications or changes to the criteria it uses to assign equity credit to securities such as the series C preferred stock (Ratings Event), we may redeem the series C preferred stock, in whole but not in part, at any time within 120 days after the conclusion of any review or appeal process instituted by us following the occurrence of the Ratings Event or, if no such review or appeal process is available or sought, the occurrence of such Ratings Event, at a redemption price in cash equal to $1,020 per share (102% of the liquidation preference per share).
Dividends
Dividends on the series C preferred stock, when, as and if declared by our board of directors or an authorized committee thereof, are payable in cash, on a cumulative basis, semi-annually in arrears beginning on October 15, 2020. Dividends on the series C preferred stock will be cumulative whether or not:
▪we have earnings;
▪the payment of such dividends is then permitted under California law;
▪such dividends are authorized or declared; and
▪any agreements to which we are a party prohibit the current payment of dividends, including any agreement relating to our indebtedness.
We accrue dividends on the series C preferred stock on a monthly basis. The dividend rate from and including June 19, 2020 to, but excluding, October 15, 2025 is 4.875% per annum of the $1,000 liquidation preference per share. The dividend rate will reset on October 15, 2025 and on October 15 of every fifth year after 2025 and, for each five-year period following such reset dates, will be a per annum rate equal to the Five-year U.S. Treasury Rate (as defined in the certificate of determination of preferences of the series C preferred stock) as of the second business day prior to such reset date, plus a spread of 4.550%, of the $1,000 liquidation preference per share.
Voting Rights
The holders of series C preferred stock do not have any voting rights, except with respect to any authorization, creation or increase in the authorized amount of any class or series of capital stock ranking senior to the series C preferred stock, certain
amendments to the terms of the series C preferred stock, in certain other limited circumstances and as otherwise specifically required by California law. In addition, whenever dividends on any shares of series C preferred stock have not been declared and paid or have been declared but not paid for three or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the series C preferred stock, voting together as a single class with holders of any and all other outstanding series of preferred stock of equal rank having similar voting rights, will be entitled to elect two directors who satisfy certain requirements to fill such two newly created directorships. This voting right will terminate when all accumulated and unpaid dividends on the series C preferred stock have been paid in full and, upon such termination and the termination of the same voting rights of all other holders of outstanding series of preferred stock that have such voting rights, the term of office of each director elected pursuant to such rights will terminate and the authorized number of directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.
Ranking
The series C preferred stock ranks, with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:
▪senior to our common stock and each other class or series of our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;
▪on parity with each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks on parity with the series C preferred stock;
▪junior to each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks senior to the series C preferred stock;
▪junior to our existing and future indebtedness and other liabilities; and
▪structurally subordinated to all existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.
SOCALGAS PREFERRED STOCK
SoCalGas is authorized to issue up to an aggregate of 11 million shares of preferred stock, series preferred stock and preference stock. The table below presents preferred stock outstanding at SoCalGas:
None of SoCalGas’ outstanding preferred stock is callable, and no shares are subject to mandatory redemption.
All outstanding shares have one vote per share, cumulative preferences as to dividends and liquidation preferences of $25 per share plus any unpaid dividends.
In addition to the outstanding preferred stock above, SoCalGas’ articles of incorporation authorize 5 million shares of series preferred stock and 5 million shares of preference stock, both without par value and with cumulative preferences as to dividends and liquidation value. The preference stock would rank junior to all series of preferred stock and series preferred stock. Other rights and privileges of any new series of such stock would be established by the SoCalGas board of directors at the time of issuance.
NOTE 14. SEMPRA - SHAREHOLDERS’ EQUITY AND EARNINGS PER COMMON SHARE
SEMPRA COMMON STOCK REPURCHASES
On September 11, 2007, our board of directors authorized the repurchase of shares of our common stock, provided that the amounts spent for such purpose do not exceed the greater of $2 billion or amounts spent to purchase no more than 40 million shares. On July 1, 2020, we entered into an ASR program under which we prepaid $500 million to repurchase shares of our common stock in a share forward transaction. The total number of shares purchased was determined by dividing the $500 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 July 2, 2020 through August 4, 2020, minus a fixed discount. The ASR program was completed on August 4, 2020 with an aggregate of 4,089,375 shares of Sempra common stock repurchased at an average price of $122.27 per share. Following the completion of the ASR program, the aggregate dollar amount authorized by the September 11, 2007 share repurchase authorization was exhausted.
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. No shares were repurchased under this authorization in 2020.
Beginning on November 17, 2021, we executed a series of open market repurchases for which we paid $300 million to repurchase shares of our common stock in the open market. The repurchases were completed on December 7, 2021 with an aggregate of 2,422,758 shares of Sempra common stock repurchased at a weighted-average purchase price of $123.83 per share, excluding commissions.
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 at an average price of $135.80 per share. The total number of shares purchased 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 July 6, 2020 repurchase authorization.
SETTLEMENT OF FORWARD SALE AGREEMENTS
In 2019, we received $728 million (net of underwriting discounts of $13 million) from the settlement of 7,156,185 shares of our common stock at a forward sale price of $101.74 per share related to our January 2018 common stock offering.
In 2019, we received $1,066 million (net of underwriting discounts of $18 million) from the settlement of 9,750,000 shares of our common stock at a forward sale price of $109.33 per share related to our July 2018 common stock offering.
EARNINGS PER COMMON SHARE
Basic EPS is calculated by dividing earnings attributable to common shares (from both continuing and discontinued operations) by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.
(1) Includes fully vested RSUs held in our Deferred Compensation Plan of 453 in 2021, 537 in 2020 and 617 in 2019. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.
(2) Due to market fluctuations of both Sempra common stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 10, dilutive RSUs may vary widely from period-to-period.
The potentially dilutive impact from stock options and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS for 2021, 2020 and 2019 excludes potentially dilutive shares related to stock options and RSUs of 211,155, 187,028 and 80,281, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future.
The potentially dilutive impact from the forward sale of our common stock pursuant to the forward sale agreements that we discuss above is reflected in our diluted EPS calculation using the treasury stock method. We have fully settled all forward sale agreements and those shares are included in weighted-average common shares outstanding for basic EPS.
The potentially dilutive impact from our mandatory convertible preferred stock is calculated under the if-converted method until the mandatory conversion date. After the mandatory conversion date, the converted shares are included in weighted-average common shares outstanding for basic EPS. As we discuss in Note 13, we converted our series A preferred stock into common stock on January 15, 2021 and our series B preferred stock into common stock on July 15, 2021. The computation of diluted EPS for the years ended December 31, 2021, 2020 and 2019 excludes 2,272,117, 17,889,365 and 17,471,375 potentially dilutive shares related to our mandatory convertible preferred stock, respectively, because to include them would be antidilutive for those periods.
We are authorized to issue 750 million shares of no par value common stock. The following table provides common stock activity for the last three years.
(1) Includes dividend equivalents.
(2) Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.
(3) In 2021 and 2020, includes shares repurchased under the repurchase programs that we discuss above. Generally, we purchase shares of our common stock or units from LTIP participants who elect to sell to us a sufficient number of vested RSUs to meet minimum statutory tax withholding requirements.
NOTE 15. SAN ONOFRE NUCLEAR GENERATING STATION
SDG&E has a 20% ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which permanently ceased operations in June 2013 after an extended outage as a result of issues with the steam generators used in the facility. Edison, the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the NRC to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.
SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of costs. SDG&E’s share of operating expenses is included in Sempra’s and SDG&E’s Consolidated Statements of Operations.
NUCLEAR DECOMMISSIONING AND FUNDING
As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Major decommissioning work began in 2020. We expect the majority of the decommissioning work to take approximately 10 years. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be completed once Units 2 and 3 are dismantled and the spent fuel is removed from the site. The spent fuel is currently being stored
on-site, until the DOE identifies a spent fuel storage facility and puts in place a program for the fuel’s disposal, as we discuss below. SDG&E is responsible for approximately 20% of the total decommissioning cost.
The Samuel Lawrence Foundation filed a writ petition under the California Coastal Act in LA Superior Court in December 2019 seeking to invalidate the coastal development permit and to obtain injunctive relief to stop decommissioning work. The petition was denied in September 2021. In December 2021, the foundation filed a notice of appeal. In September 2020, the foundation filed another writ petition under the California Coastal Act in LA Superior Court seeking to set aside the CCC’s July 2020 approval of the inspection and maintenance plan for the SONGS’ canisters and to obtain injunctive relief to stop decommissioning work. In December 2021, the foundation filed a request for dismissal. To date, decommissioning work has not been interrupted as a result of these writ petitions.
In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. Amounts that were collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. SDG&E classifies debt and equity securities held in the NDT as available-for-sale. The NDT assets are presented on the Sempra and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.
Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In December 2021, SDG&E received authorization from the CPUC to access NDT funds of up to $78 million for forecasted 2022 costs.
In September 2020, the IRS and the U.S. Department of the Treasury published final regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The final regulations adopted most of the provisions of the proposed regulations issued in December 2016. The final regulations apply to taxable years ending on or after September 4, 2020 and confirm that the definition of “nuclear decommissioning costs” includes amounts related to the storage of spent nuclear fuel at both on-site and off-site ISFSIs.
The final regulations also clarify that costs incurred for ISFSIs that may be or are expected to be reimbursed by the DOE may be paid or reimbursed from a qualified trust fund. Accordingly, the final regulations allow SDG&E the option to access qualified trust funds to recover spent fuel storage costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below.
Nuclear Decommissioning Trusts
The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT on the Sempra and SDG&E Consolidated Balance Sheets. We provide additional fair value disclosures for the NDT in Note 12.
(1) Maturity dates are 2022-2052.
(2) Maturity dates are 2022-2056.
(3) Maturity dates are 2022-2072.
The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.
Net unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.
ASSET RETIREMENT OBLIGATION
The present value of SDG&E’s ARO related to decommissioning costs for all three SONGS units was $568 million at December 31, 2021 and is based on a cost study prepared in 2020, which will be submitted to the CPUC in the first half of 2022. The ARO for Units 2 and 3 reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $79 million in 2022, $66 million in 2023, $77 million in 2024, $46 million in 2025, $52 million in 2026, and $718 million thereafter.
U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL
Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC. The ISFSI will operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.
The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. In November 2019, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims for the time period from January 2017 through July 2018, which is pending DOE approval. It is unclear when Edison will pursue litigation claims for spent fuel management costs incurred on or after August 1, 2018. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.
NUCLEAR INSURANCE
SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $110 million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $450 million insurance limit, this additional coverage would be available to provide a total of $560 million in coverage limits per incident.
The SONGS owners have nuclear property damage insurance of $130 million, which exceeds the minimum federal requirements of $50 million. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $4.3 million of retrospective premiums based on overall member claims.
The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act) of $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.
NOTE 16. COMMITMENTS AND CONTINGENCIES
LEGAL PROCEEDINGS
We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed, and in some cases have exceeded, applicable insurance coverage and could materially adversely affect our business, results of operations, financial condition, cash flows and/or prospects. Unless otherwise indicated, we are unable to reasonably estimate possible losses or a range of losses in excess of any amounts accrued.
At December 31, 2021, loss contingency accruals for legal matters, including associated legal fees and regulatory matters related to the Leak, that are probable and estimable were $2,086 million for Sempra, including $4 million for SDG&E and $2,006 million for SoCalGas. Amounts for Sempra and SoCalGas include $1,980 million for matters related to the Leak, which we discuss below. We discuss our policy regarding accrual of legal fees in Note 1.
SoCalGas
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 in Los Angeles County. As described below, numerous lawsuits, investigations and regulatory proceedings have been initiated in response to the Leak, resulting in significant costs, which together with other Leak-related costs are discussed below in “Cost Estimates, Accounting Impact and Insurance.”
Civil Litigation - Litigation Subject to Agreements to Resolve. As of February 18, 2022, approximately 390 lawsuits, including approximately 36,000 plaintiffs (the Individual Plaintiffs) were pending against SoCalGas and Sempra related to the Leak. All these cases are coordinated before a single court in the LA Superior Court for pretrial management.
In November 2017, in the coordinated proceeding, a Third Amended Consolidated Master Case Complaint for Individual Actions was filed on behalf of the Individual Plaintiffs, through which their separate lawsuits are managed for pretrial purposes. The consolidated complaint asserts causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment, loss of consortium, wrongful death and violations of Proposition 65 against SoCalGas and Sempra (excluding the Proposition 65 claims, the Individual Plaintiff Litigation). The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs of future medical monitoring, civil penalties, and attorneys’ fees.
In October 2018 and January 2019, complaints were filed on behalf of 51 firefighters stationed near the Aliso Canyon natural gas storage facility who allege they were injured by exposure to chemicals released during the Leak. The complaints against SoCalGas and Sempra assert causes of actions for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment and loss of consortium. The complaints seek compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, and attorneys’ fees. These complaints are included in the coordinated proceeding and the Individual Plaintiff Litigation.
On September 26, 2021, SoCalGas and Sempra entered into an agreement with counsel representing over 80% of the plaintiffs in the Individual Plaintiff Litigation to resolve the claims of all Individual Plaintiffs for a payment of up to $1.8 billion. The agreement is subject to acceptance by no fewer than roughly 97% of all plaintiffs in the Individual Plaintiff Litigation by June 1, 2022, although SoCalGas and Sempra have the right to waive such condition. The agreement, which requires each plaintiff who accepts a settlement to release all such plaintiff’s claims against SoCalGas, Sempra and their respective affiliates related to the Individual Plaintiff Litigation and the Leak, provides that the settlement amount will be reduced based on the number of plaintiffs who do not accept. The LA Superior Court has approved the process to allocate payments among the plaintiffs. The plaintiffs who do not agree to participate in the settlement will be able to continue to pursue their claims. Pursuant to the agreement, the Individual Plaintiff Litigation has been stayed.
In January 2017, two consolidated class action complaints were filed against SoCalGas and Sempra, one on behalf of a putative class of persons and businesses who own or lease real property within a five-mile radius of the well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). The Property Class Action asserts claims for strict liability for ultra-hazardous activities, negligence, negligence per se, violation of the California Unfair Competition Law, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action asserts a claim for violation of the California Unfair Competition Law. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees.
On September 26, 2021, SoCalGas and Sempra entered into an agreement to settle the Property Class Action for a total amount of $40 million. If, following a fairness hearing at which any objections to the settlement will be heard, the LA Superior Court gives final approval of the settlement, the agreement provides for a release of SoCalGas, Sempra and their respective affiliates from all claims related to the Leak by all property class members who do not opt out of the class. Members of the property class who opt out of the settlement will have the right to pursue their claims on an individual basis.
On September 27, 2021, SoCalGas and Sempra entered into an agreement to settle the individual claims of the named plaintiffs in the Business Class Action for a total amount of $100,000 in exchange for a dismissal and release of SoCalGas, Sempra and their respective affiliates from all claims related to the Leak. The complaint was dismissed in January 2022.
The Third Amended Consolidated Master Case Complaint for Individual Actions includes claims for violation of Proposition 65 seeking penalties for alleged violation of requirements to warn about certain chemical exposures as a result of the Leak. On November 4, 2021, SoCalGas entered into an agreement to settle these claims for a payment of approximately $2 million; in addition, SoCalGas agreed to implement certain measures to reduce emissions at the Aliso Canyon natural gas storage facility and to provide warnings to residents if benzene measured at the facility’s fence line exceeds certain levels. In January 2022, the LA Superior Court entered a consent judgment resolving the Proposition 65 claims.
In October 2018 and October 2020, five property developers (the Developer Plaintiffs) filed complaints against SoCalGas and Sempra alleging causes of action for strict liability, negligence per se, negligence, negligent interference, continuing nuisance, permanent nuisance, inverse condemnation and violation of the California Unfair Competition Law and California Public Utilities Code section 2106, as well as claims for negligence against certain directors of SoCalGas. The complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. In October 2021, the claims against the individual SoCalGas directors were dismissed. In January 2022, SoCalGas and Sempra entered into an agreement to settle the claims of one of the Developer Plaintiffs, and its complaint was dismissed.
An adverse ruling in any of the lawsuits in the Individual Plaintiff Litigation filed by plaintiffs who do not agree to settle, any lawsuits filed by property class members who opt out of the Property Class Action settlement or by members of the putative Business Class Action could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects. In addition, there can be no assurance that the conditions to resolve the Individual Plaintiff Litigation will be satisfied or that the LA Superior Court will approve the settlement for the Property Class Action.
In addition, a federal securities class action alleging violation of the federal securities laws was filed against Sempra and certain of its officers in July 2017 in the U.S. District Court for the Southern District of California. In March 2018, the court dismissed the action with prejudice, and in February 2021, the U.S. Court of Appeals for the Ninth Circuit affirmed the dismissal. The time for appeal has passed and, as a result, this represents the final judgment in this proceeding.
Civil Litigation - Unresolved Litigation. The claims of four of the Developer Plaintiffs remain pending, and the LA Superior Court has scheduled a trial in October 2022. SoCalGas has engaged in settlement discussions with the Developer Plaintiffs.
Four shareholder derivative actions were filed alleging breach of fiduciary duties against certain officers and certain directors of Sempra and/or SoCalGas. Three of the actions were joined in an Amended Consolidated Shareholder Derivative Complaint, which was dismissed with prejudice in January 2021. The plaintiffs have appealed the dismissal. The remaining action was also dismissed but plaintiffs were given leave to amend their complaint.
Regulatory Proceedings. In January 2016, CalGEM and the CPUC directed an independent analysis of the technical root cause of the Leak to be conducted by Blade. In May 2019, Blade released its report, which concluded that the Leak was caused by a failure of the production casing of the well due to corrosion and that attempts to stop the Leak were not effectively conducted, but did not identify any instances of non-compliance by SoCalGas. Blade concluded that SoCalGas’ compliance activities conducted prior to the Leak did not find indications of a casing integrity issue. Blade opined, however, that there were measures, none of which were required by gas storage regulations at the time, that could have been taken to aid in the early identification of corrosion and that, in Blade’s opinion, would have prevented or mitigated the Leak. The report also identified well safety practices and regulations that have since been adopted by CalGEM and implemented by SoCalGas.
In June 2019, the CPUC opened an OII to consider penalties against SoCalGas for the Leak, which it later bifurcated into two phases. The first phase will consider whether SoCalGas violated California Public Utilities Code Section 451 or other laws, CPUC orders or decisions, rules or requirements, 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, whether SoCalGas cooperated sufficiently with the SED of the CPUC and Blade during the pre-formal investigation, and whether any of the mitigation measures proposed by Blade should be implemented to the extent not already done. The SED, based largely on the Blade report, has alleged a total of 324 violations in the first phase, asserting that SoCalGas violated California Public Utilities Code Section 451 and failed to cooperate in the investigation and to keep proper records. Hearings on a subset of issues began in March 2021. 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 cooperate sufficiently with the SED as determined by the CPUC in the first phase. In addition, the second phase will determine the amounts of various costs incurred by SoCalGas and other parties in connection with the Leak and the ratemaking treatment or other
disposition of such costs, which could result in little or no recovery of such costs by SoCalGas. SoCalGas has engaged in settlement discussions with the SED in connection with this proceeding.
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, but excluding issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The first phase of the proceeding established a framework for the hydraulic, production cost and economic modeling assumptions for the potential reduction in usage or elimination of the Aliso Canyon natural gas storage facility. Phase 2 of the proceeding, which is evaluating the impacts of reducing or eliminating the Aliso Canyon natural gas storage facility using the established framework and models, began in the first quarter of 2019. In December 2019, the CPUC added a third phase of the proceeding and engaged a consultant who is analyzing alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated in either the 2027 or 2035 timeframe. In July 2021, the CPUC combined Phase 2 and Phase 3 and modified the scope of Phase 3 to also address potential implementation of alternatives to the Aliso Canyon natural gas storage facility if the CPUC determines that the Aliso Canyon natural gas storage facility should be permanently closed. The CPUC also added all California IOUs as parties to the proceeding and encouraged all load serving entities in the Los Angeles Basin to join the proceeding.
In November 2020, the CPUC issued a decision on the interim range of gas inventory levels at the Aliso Canyon natural gas storage facility, setting the interim range between 0 Bcf and 34 Bcf. In November 2021, the CPUC issued a decision approving a new interim range of gas inventory levels of up to 41.16 Bcf. The CPUC may issue future changes to this interim range of authorized gas inventory levels before issuing a final inventory determination within the SB 380 OII proceeding.
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.
Cost Estimate, Accounting Impact and Insurance. SoCalGas has incurred significant costs related to the Leak, primarily for temporary relocation of community residents; to control the well and stop the Leak; to mitigate the natural gas released; to purchase natural gas to replace what was lost through the Leak; to defend against and, in certain cases, settle, civil and criminal litigation arising from the Leak; to pay the costs of the government-ordered response to the Leak, including the costs for Blade to conduct the root cause analysis described above; to respond to various government and agency investigations regarding the Leak; and to comply with increased regulation imposed as a result of the Leak. At December 31, 2021, SoCalGas estimates these costs related to the Leak are $3,221 million (the cost estimate), which includes $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.
In 2020, SoCalGas recorded $484 million in costs, inclusive of estimated legal costs, related to settlement discussions in connection with civil litigation and regulatory matters described above. Of this amount, $177 million was recorded in Insurance Receivable for Aliso Canyon Costs on the SoCalGas and Sempra Consolidated Balance Sheets and $307 million ($233 million after tax) was recorded in Aliso Canyon Litigation and Regulatory Matters on the SoCalGas and Sempra Consolidated Statements of Operations.
As a result of entering into the agreements described under “Civil Litigation - Litigation Subject to Agreements to Resolve” above, and other continuing settlement negotiations, SoCalGas recorded total charges of $1.59 billion ($1.15 billion after tax) in 2021 in Aliso Canyon Litigation and Regulatory Matters on the SoCalGas and Sempra Consolidated Statements of Operations. 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 these accruals.
Except for the amounts paid or estimated to settle certain legal and regulatory matters as described above, 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 above in “Civil Litigation - Unresolved Litigation” and “Regulatory Proceedings” 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. At 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.
Sempra Infrastructure
Energía Costa Azul
We describe below certain land and customer disputes and permit challenges affecting our ECA Regas Facility and our proposed ECA LNG liquefaction projects. One or more unfavorable final decisions on these disputes or 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.
Land Disputes. Sempra Infrastructure has been engaged in a long-running land dispute relating to property adjacent to its ECA Regas Facility that allegedly overlaps with land owned by the ECA Regas Facility (the facility, however, is not situated on the land that is the subject of this dispute), as follows:
▪A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of SEDATU in 2006 to issue title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title to the claimant and cause it to be registered. Both SEDATU and Sempra Infrastructure challenged the ruling due to lack of notification of the underlying process. In May 2019, a federal court in Mexico reversed the ruling and ordered a retrial, which is pending resolution.
▪In a separate proceeding, the claimant filed suit to reinitiate an administrative procedure at SEDATU to obtain the property title that was previously dismissed. In April 2021, the Agrarian Court ordered that the administrative procedure be restarted.
In addition, four cases involving two adjacent areas of real property on which part of the ECA Regas Facility is situated, each brought by a single plaintiff or her descendants, remain pending against the facility, as follows:
▪The first disputed area is subject to a claim in the federal Agrarian Court that has been ongoing since 2006, in which the plaintiff seeks to annul the property title for a portion of the land on which the ECA Regas Facility is situated and to obtain possession of a different parcel that allegedly overlaps with the site of the ECA Regas Facility. The proceeding, which seeks an order that SEDATU annul the ECA Regas Facility’s competing property title, was initiated in 2006 and, in July 2021, a decision was issued in favor of the ECA Regas Facility. The plaintiff appealed, and in February 2022, the appellate court confirmed the ruling in favor the ECA Regas Facility and dismissed the appeal.
▪The second disputed area is one parcel adjacent to the ECA Regas Facility that allegedly overlaps with land on which the ECA Regas Facility is situated, which is subject to a claim in the federal Agrarian Court and two claims in Mexican civil courts. The ECA Regas Facility first bought the property from the federal government in 2003; however, to resolve an ownership controversy, in 2008, the ECA Regas Facility reached a financial settlement with the plaintiff to eliminate an adverse claim to our title. Nevertheless, the plaintiff sued in 2013 for the nullity of both titles. The Agrarian Court ruled in favor of the plaintiff in May 2021, nullifying the first property title. Sempra Infrastructure appealed the ruling in July 2021, which is pending resolution. The ECA Regas Facility continues to hold the second property title to the land. The two civil court proceedings, which seek to invalidate the contract by which the ECA Regas Facility purchased for the second time the applicable parcel of land on which the ECA Regas Facility is situated on the grounds that the purchase price was allegedly unfair, are progressing at different stages. In the first civil case, initiated in 2013, the court ruled in favor of the ECA Regas Facility, and the final decision was affirmed on a federal appeal. The descendants of the same plaintiff filed the second civil case in 2019, which was dismissed by the court. However, the dismissal has been appealed, which is pending the appellate court’s ruling.
Certain of these land disputes involve land on which portions of the ECA LNG liquefaction facilities, including ECA LNG Phase 1 currently under construction, are proposed to be situated or on which portions of the ECA Regas Facility that would be necessary for the operation of the proposed ECA LNG liquefaction facilities are situated.
Environmental and Social Impact Permits. Several administrative challenges are pending before Mexico’s Secretariat of Environment and Natural Resources (the Mexican environmental protection agency) and Federal Tax and Administrative Courts, seeking revocation of the environmental impact authorization issued to the ECA Regas Facility in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.
In 2018 and 2021, three related claimants filed separate challenges in the federal district court in Ensenada, Baja California in relation to the environmental and social impact permits issued by each of ASEA and SENER to ECA LNG authorizing natural gas liquefaction activities at the ECA Regas Facility, as follows:
▪In the first case, the court issued a provisional injunction in September 2018. In December 2018, ASEA approved modifications to the environmental permit that facilitate the development of the proposed natural gas liquefaction facility in two phases. In May 2019, the court canceled the provisional injunction. The claimant appealed the court’s decision canceling the injunction, but was not successful. The claimant’s underlying challenge to the permits remains pending.
▪In the second case, the initial request for a provisional injunction was denied. That decision was reversed on appeal in January 2020, resulting in the issuance of a new injunction against the permits that were issued by ASEA and SENER. This injunction has uncertain application absent clarification by the court. The claimants petitioned the court to rule that construction of natural gas liquefaction facilities violated the injunction, and in February 2022, the court ruled in favor of the ECA Regas Facility, meaning that the natural gas liquefaction activities have not been affected. The claimants may appeal this ruling.
▪In the third case, a group of residents filed a complaint in June 2021 against various federal and state authorities alleging deficiencies in the public consultation process for the issuance of the permits. The request for an initial injunction was denied and the claimants have appealed, which is pending the appellate court’s ruling.
Customer Dispute. In May 2020, the two third-party capacity customers at the ECA Regas Facility, Shell Mexico and Gazprom, asserted that a 2019 update of the general terms and conditions for service at the facility, as approved by the CRE, resulted in a breach of contract by Sempra Infrastructure and a force majeure event. Citing these circumstances, the customers subsequently stopped making payments of amounts due under their respective LNG storage and regasification agreements. Sempra Infrastructure has rejected the customers’ assertions and has drawn on the customers’ letters of credit provided as payment security. The parties engaged in discussions under the applicable contractual dispute resolution procedures without coming to a mutually acceptable resolution. In July 2020, Shell Mexico submitted a request for arbitration of the dispute and although Gazprom has joined the proceeding, Gazprom has since replenished the amounts drawn on its letter of credit and has resumed making regular monthly payments under its LNG storage and regasification agreement. As a consequence, Sempra Infrastructure is not currently drawing on Gazprom’s letter of credit but expects to continue to draw on Shell Mexico’s letter of credit. Sempra Infrastructure intends to avail itself of its available claims, defenses, rights and remedies in the arbitration proceeding, including seeking dismissal of the customers’ claims. In addition to the arbitration proceeding, Shell Mexico also filed a constitutional challenge to the CRE’s approval of the update to the general terms and conditions and an additional constitutional claim against the issuance of the liquefaction permit. Shell Mexico’s request to stay the CRE’s approval of the general terms and conditions was denied and upheld on appeal. The claim regarding the liquefaction permit issuance was denied and is currently on appeal. A hearing on the merits of the arbitration case was held in October 2021.
Sonora Pipeline
Guaymas-El Oro Segment. Sempra Infrastructure’s Sonora natural gas pipeline consists of two segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. In 2015, the Yaqui tribe, with the exception of some members living in the Bácum community, granted its consent and a right-of-way easement agreement for the construction of the Guaymas-El Oro segment of the Sonora natural gas pipeline that crosses its territory. Representatives of the Bácum community filed a legal challenge in Mexican federal court demanding the right to withhold consent for the project, the stoppage of work in the Yaqui territory and damages. In 2016, the judge granted a suspension order that prohibited the construction of such segment through the Bácum community territory. Because the pipeline does not pass through the Bácum community, Sempra Infrastructure did not believe the 2016 suspension order prohibited construction in the remainder of the Yaqui territory. Construction of the Guaymas-El Oro segment was completed, and commercial operations began in May 2017.
Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory that has made that section inoperable since August 2017 and, as a result, Sempra Infrastructure declared a force majeure event. In 2017, an appellate court ruled that the scope of the 2016 suspension order encompassed the wider Yaqui territory, which has prevented Sempra Infrastructure from making repairs to put the pipeline back in service. In July 2019, a federal district court ruled in favor of Sempra Infrastructure and held that the Yaqui tribe was properly consulted and that consent from the Yaqui tribe was properly received. Representatives of the Bácum community appealed this decision, causing the suspension order preventing Sempra Infrastructure from repairing the damage to the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory to remain in place until the appeals process is exhausted. In December 2021, the court of appeals referred the matter to Mexico’s Supreme Court.
Sempra Infrastructure exercised its rights under the contract, which included seeking force majeure payments for the two-year period such force majeure payments were required to be made, which ended in August 2019.
In July 2019, the CFE filed a request for arbitration generally to nullify certain contract terms that provide for fixed capacity payments in instances of force majeure and made a demand for substantial damages in connection with the force majeure event. In September 2019, the arbitration process ended when Sempra Infrastructure and the CFE reached an agreement to restart natural gas transportation service on the earlier of completion of repair of the damaged pipeline or January 15, 2020, and to modify the tariff structure and extend the term of the contract by 10 years. Subsequently, Sempra Infrastructure and the CFE agreed to extend the service start date multiple times, most recently to March 14, 2022. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is repaired. If the pipeline is not repaired by March 14, 2022, and the parties do not agree on a new service start date, Sempra Infrastructure retains the right to terminate the contract and seek to recover its reasonable and documented costs and lost profits. Discussions with the CFE regarding the future of the pipeline, including the potential re-routing of a portion of the pipeline, are underway in accordance with a non-binding MOU announced in January 2022 that, among other matters, addresses efforts to restart service on the pipeline. Sempra Infrastructure intends to enter into a definitive agreement with respect to the pipeline in the first quarter of 2022.
At December 31, 2021, Sempra Infrastructure had $432 million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if Sempra Infrastructure is unable to make such 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, which in each case could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Sasabe-Puerto Libertad-Guaymas Segment. In June 2014, Sempra Infrastructure and a landowner agreed to enter into a voluntary right-of-way easement agreement for the construction and operation of a seven-mile section of the 314-mile Sasabe-Puerto Libertad-Guaymas segment of the Sonora natural gas pipeline on the landowner’s property. However, in 2015, the landowner filed a complaint demanding the easement agreement be nullified. In September 2021, a definitive and non-appealable judgment was issued declaring the easement agreement nullified and ordering the removal of the pipeline from the landowner’s property. The execution of the judgment is suspended as a result of an amparo lawsuit filed by the CFE as an interested third party that did not participate in the litigation. Sempra Infrastructure filed a special judicial action asking the civil court to acknowledge the existence of the easement and to determine the consideration the landowner should receive in exchange for the easement. The failure to stay this judgment 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, which 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
We describe below certain actions by the Mexican government that could have a material impact on the energy sector 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 described below 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.
Transmission Rates for Legacy Generation Facilities. In May 2020, the CRE approved an update to the transmission rates included in legacy renewable and cogeneration energy contracts based on the claim that the legacy transmission rates did not reflect fair and proportional costs for providing the applicable services and, therefore, created inequitable competitive conditions. Three of Sempra Infrastructure’s renewable energy facilities (Don Diego Solar, Border Solar and Ventika) are currently holders of contracts with such legacy rates, and under the terms of these contracts any increases in the transmission rates would be passed through directly to their customers. These renewable energy facilities have obtained injunctive relief but are required to guarantee the difference in tariffs, which could be material, until the claims are definitively resolved by the courts. The three facilities obtained favorable resolutions from a lower court and the CRE has appealed one of these decisions.
Offtakers of Legacy Generation Permits. In October 2020, the CRE approved a resolution to amend the rules for the inclusion of new offtakers of legacy generation and self-supply permits (the Offtaker Resolution), which became effective immediately. The Offtaker Resolution prohibits self-supply permit holders from adding new offtakers that were not included in the original development or expansion plans, making modifications to the amount of energy allocated to the named offtakers, and including load centers that have entered into a supply arrangement under Mexico’s Electricity Industry Law. Don Diego Solar, Border Solar and Ventika are holders of self-supply permits and are impacted by the Offtaker Resolution. In January 2022, Don Diego Solar and Border Solar obtained a favorable resolution from a Mexican federal district court that we expect the CRE will appeal. If Sempra Infrastructure is not able to obtain legal protection for these impacted facilities, Sempra Infrastructure expects it will sell Border Solar’s capacity and a portion of Don Diego Solar’s capacity affected by the Offtaker Resolution into the spot market. Currently, prices in the spot market are significantly lower than the fixed prices in the PPAs that were entered into through self-supply permits. At December 31, 2021, Sempra Infrastructure had $14 million in other intangible assets, net, related to these self-supply permits previously granted by the CRE and impacted by the Offtaker Resolution that could be subject to impairment if Sempra Infrastructure is unable to obtain adequate legal protection. Sempra Infrastructure has filed lawsuits against the Offtaker Resolution and received injunctive relief pending final resolution.
Amendments to Mexico’s Electricity Industry Law. In March 2021, the Mexican government published a decree with amendments to Mexico’s Electricity Industry Law that include some public policy changes, including establishing priority of dispatch for CFE plants over privately owned plants. According to the decree, these amendments were to become effective on March 10, 2021, and SENER, the CRE and CENACE were to have 180 calendar days to modify, as necessary, all resolutions, policies, criteria, manuals and other regulations applicable to the power industry to conform with this decree. However, a Mexican court issued a suspension of the amendments on March 19, 2021, and it is expected that Mexico’s Supreme Court will ultimately settle the matter. If the proposed amendments are affirmed by the Supreme Court, the CRE may be required to revoke self-supply permits granted under the former electricity law, which were grandfathered when the new Electricity Industry Law was enacted, under a legal standard that is ambiguous and not well defined under the law.
Amendments to Mexico’s Hydrocarbons Law. In May 2021, amendments to Mexico’s Hydrocarbons Law were published and became effective. The amendments grant SENER and the CRE additional powers to suspend and revoke permits related to the midstream and downstream sectors. Suspension of permits will be determined by SENER or the CRE when a danger to national security, energy security, or to the national economy is foreseen. Likewise, new grounds for the revocation of permits are in place if the permit holder (i) carries out its activity with illegally imported products; (ii) fails, on more than one occasion, to comply with the provisions applicable to quantity, quality and measurement of the products; or (iii) modifies the technical conditions of its infrastructure without authorization. Additionally, in the case of existing permits, authorities will revoke those 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. All of Sempra Infrastructure’s facilities participating in the hydrocarbons sector filed lawsuits against the initiative to reform the Hydrocarbons Law and received injunctive relief pending a
final resolution by the courts. In May 2021, a Mexican district court ordered the suspension of several of the provisions of the amendments with general application across the sector. In 2021, district courts issued judgments that the amendments do not affect the interests of the companies at this time and, as a result, dismissed the amparo lawsuits filed by several companies in the market, including three of the five lawsuits filed by Sempra Infrastructure. These judgments have been appealed and the granted suspensions will remain valid until the lawsuits are definitively resolved.
Amendments to Mexico’s General Foreign Trade Rules. In June 2021, amendments to Mexico’s General Foreign Trade Rules went into effect, which establish that only state-owned companies may import and export hydrocarbons, refined products, petrochemicals, and biofuels through channels other than those authorized (LDA authorization). These amendments prevent non-state-owned companies from (i) obtaining LDA authorizations, which affect new projects that have not obtained such approval, and (ii) renewing existing LDA authorizations, which affect operational projects and those under construction. The ECA Regas Facility and the Veracruz terminal have LDA authorizations that are valid through 2023 and, as a preventive measure, have filed amparo claims to challenge the newly introduced barrier to renewing their existing LDA authorizations. In order to start operations at terminals currently under construction or in development in the vicinity of Topolobampo, Manzanillo and Ensenada, including the proposed ECA LNG liquefaction projects, Sempra Infrastructure filed amparo claims to challenge such amendments that prevent them from obtaining LDA authorizations in the future. In October and November of 2021, the Mexican government published new General Foreign Trade Rules in which private companies are allowed to obtain LDA authorizations and, as a consequence, the amparo claims filed by the ECA Regas Facility and the Veracruz terminal have been dismissed by the courts, while the appropriate court is being determined to hear the amparo claim for future LDA authorizations. There can be no assurance that new or renewed LDA authorizations will be obtained in a timely manner or at all.
Proposed Constitutional Reform in Mexico. In September 2021, the President of Mexico presented a constitutional reform initiative with the stated goal of preserving energy security and self-sufficiency, and a continuous supply of electricity to the country’s population, as a condition for guaranteeing national security and the human right to a decent life. The CRE and the National Commission of Hydrocarbons would be dissolved, and their functions would be carried out by SENER. CENACE would be reinstated to the CFE, and the CFE would be responsible for generating, conducting, transforming, distributing and supplying electricity, and would be the only entity allowed to commercialize electric energy in Mexico. Electricity generation permits and contracts for the sale of electricity and RECs to the CFE, including permits at all of Sempra Infrastructure’s operational power generation facilities, would be canceled. The public electricity supply service would be provided exclusively by the CFE, which may acquire up to 46% of required energy from the private sector. Only certain private power plants would be permitted to continue generating electricity and compete to offer the CFE the lowest production costs.
The initiative must first be submitted to a vote and approved in the respective plenary sessions of the Chamber of Deputies and the Chamber of Senators in Mexico. Additionally, the initiative must be approved by a two-thirds vote of Mexico’s Federal Congress and by the majority of the legislatures of the Mexican States and published in the Federal Official Gazette to be in force. Sempra Infrastructure is following this legislative procedure while assessing alternatives for its project companies. If passed in its current form, the initiative could have a material adverse effect on our business, results of operations, financial condition, cash flows and/or prospects, our ability to recover the carrying values of our investments in Mexico, and our ability to operate existing facilities and develop new energy projects in the country.
Other Litigation
RBS Sempra Commodities
Sempra holds an equity method investment in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. RBS, now NatWest Markets plc, our partner in the JV, paid an assessment of £86 million (approximately $138 million in U.S. dollars) in October 2014 to HMRC for denied VAT refund claims filed in connection with the purchase of carbon credit allowances by RBS SEE, a subsidiary of RBS Sempra Commodities. RBS SEE was subsequently sold to J.P. Morgan Chase & Co. and later to Mercuria Energy Group, Ltd. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid on certain carbon credit purchases during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In July 2021, RBS entered into a settlement with HMRC that resolved this matter.
In 2015, liquidators filed a claim in the High Court of Justice against RBS and Mercuria Energy Europe Trading Limited (the Defendants) on behalf of 10 companies (the Liquidating Companies) that engaged in carbon credit trading via chains that included a company that traded directly with RBS SEE. The claim alleges that the Defendants’ participation in the purchase and sale of carbon credits resulted in the Liquidating Companies’ carbon credit trading transactions creating a VAT liability they were unable to pay, and that the Defendants are liable to provide for equitable compensation due to dishonest assistance and for compensation under the U.K. Insolvency Act of 1986. Trial on the matter was held in June and July of 2018. In March 2020, the High Court of Justice rendered its judgment mostly in favor of the Liquidating Companies and awarded damages of approximately £45 million
(approximately $61 million in U.S. dollars at December 31, 2021), plus costs and interest. In October 2020, the High Court of Justice issued assessed costs and interest to be approximately £21 million (approximately $28 million in U.S. dollars at December 31, 2021) as of that date, with interest continuing to accrue. The Defendants appealed and, in May 2021, the Court of Appeal set aside the High Court of Justice’s decision and ordered a retrial. The Liquidating Companies in the High Court of Justice case have applied to the Supreme Court for permission to appeal the Court of Appeal’s decision. J.P. Morgan Chase & Co. has notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and J.P. Morgan Chase & Co. has in turn sought indemnity from Sempra and RBS.
We recorded $100 million in equity losses from our investment in RBS Sempra Commodities in Equity Earnings on Sempra’s Consolidated Statement of Operations in 2020, which represented an estimate of our obligations to settle pending VAT matters and related legal costs. In 2021, we reduced this estimate by $50 million based on the settlement with HMRC on the First-Tier Tribunal case and revised assumptions on the High Court of Justice case. The final outcome of the High Court of Justice case remains uncertain.
Asbestos Claims Against EFH Subsidiaries
Certain EFH subsidiaries that we acquired as part of the merger of EFH with an indirect subsidiary of Sempra were defendants in personal injury lawsuits brought in state courts throughout the U.S. These cases alleged illness or death as a result of exposure to asbestos in power plants designed and/or built by companies whose assets were purchased by predecessor entities to the EFH subsidiaries, and generally assert claims for product defects, negligence, strict liability and wrongful death. They sought compensatory and punitive damages. As of February 18, 2022, no lawsuits are pending. Additionally, in connection with the EFH bankruptcy proceeding, approximately 28,000 proofs of claim were filed on behalf of persons who allege exposure to asbestos under similar circumstances and assert the right to file such lawsuits in the future. None of these claims or lawsuits were discharged in the EFH bankruptcy proceeding. The costs to defend or resolve these lawsuits and the amount of damages that may be imposed or incurred could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.
Ordinary Course Litigation
We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.
LEASES
A lease exists when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. We determine if an arrangement is or contains a lease at inception of the contract.
Some of our lease agreements contain nonlease components, which represent activities that transfer a separate good or service to the lessee. As the lessee for both operating and finance leases, we have elected to combine lease and nonlease components as a single lease component for real estate, fleet vehicles, power generating facilities, and pipelines, whereby fixed or in-substance fixed payments allocable to the nonlease component are accounted for as part of the related lease liability and ROU asset. As the lessor, we have elected to combine lease and nonlease components as a single lease component for real estate, power generating facilities and liquid fuels terminals if the timing and pattern of transfer of the lease and nonlease components are the same and the lease component would be classified as an operating lease if accounted for separately.
Lessee Accounting
We have operating and finance leases for real and personal property (including office space, land, fleet vehicles, machinery and equipment, warehouses and other operational facilities) and PPAs with renewable energy, energy storage and peaker plant facilities.
Some of our leases include options to extend the lease terms for up to 20 years, or to terminate the lease within one year. Our lease liabilities and ROU assets are based on lease terms that may include such options when it is reasonably certain that we will exercise the option.
Certain of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. We do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. In such cases, we recognize short-term lease costs on a straight-line basis over the lease term. Our short-term lease costs for the period reasonably reflect our short-term lease commitments.
Certain of our leases contain escalation clauses requiring annual increases in rent ranging from 2% to 5% or based on the Consumer Price Index. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year. Variable lease payments that are based on an index or rate are included in the initial measurement of our lease liability and ROU asset based on the index or rate at lease commencement and are not remeasured because of changes to the index or rate. Rather, changes to the index or rate are treated as variable lease payments and recognized in the period in which the obligation for those payments is incurred.
Similarly, PPAs for the purchase of renewable energy at SDG&E require lease payments based on a stated rate per MWh produced by the facilities, and we are required to purchase substantially all the output from the facilities. SDG&E is required to pay additional amounts for capacity charges and actual purchases of energy that exceed the minimum energy commitments. Under these contracts, we do not recognize a lease liability or ROU asset for leases for which there are no fixed lease payments. Rather, these variable lease payments are recognized separately as variable lease costs. SDG&E estimates these variable lease payments to be $297 million in 2022, $296 million in 2023, $297 million in 2024, $296 million in 2025, $290 million in 2026 and $2,779 million thereafter.
As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We also record a corresponding ROU asset, initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. We test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.
For our operating leases, our non-regulated entities recognize a single lease cost on a straight-line basis over the lease term in operating expenses. SDG&E and SoCalGas recognize this single lease cost on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.
For our finance leases, the interest expense on the lease liability and amortization of the ROU asset are accounted for separately. Our non-regulated entities use the effective interest rate method to account for the imputed interest on the lease liability and amortize the ROU asset on a straight-line basis over the lease term. SDG&E and SoCalGas recognize amortization of the ROU asset on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.
Our leases do not contain any material residual value guarantees, restrictions or covenants.
Classification of ROU assets and lease liabilities and the weighted-average remaining lease term and discount rate associated with operating and finance leases are summarized in the table below.
The components of lease costs were as follows:
(1) Includes costs capitalized in PP&E.
(2) Included in O&M, except for $22 at Sempra, $21 at SDG&E and $1 at SoCalGas in 2021, $18 at Sempra and SDG&E in 2020, and $15 at Sempra and SDG&E in 2019, which is included in Depreciation and Amortization Expense.
(3) Short-term leases with variable lease costs are recorded and presented as variable lease costs.
Cash paid for amounts included in the measurement of lease liabilities and supplemental noncash information were as follows:
The table below presents the maturity analysis of our lease liabilities and reconciliation to the present value of lease liabilities:
(1) Includes $9 in each of 2022 through 2026 and $87 thereafter related to purchased-power contracts.
(2) Substantially all amounts are related to purchased-power contracts.
Leases That Have Not Yet Commenced
SDG&E has entered into three energy storage tolling agreements, of which SDG&E expects two will commence in the third quarter of 2022 and one will commence in the second quarter of 2023. SDG&E expects to account for these agreements as operating leases upon commencement and expects the future minimum lease payments to be $8 million in 2022, $17 million in 2023, $18 million in each of 2024 through 2026 and $101 million thereafter until expiration at various dates from 2032 through 2033.
SoCalGas has entered into a fleet vehicle agreement, which SoCalGas expects will commence in May 2022. SoCalGas expects to account for the agreement as a finance lease upon commencement and expects the future minimum lease payments to be $1 million in 2022 and $2 million in each of 2023 through 2026 and $6 million thereafter until expiration in 2029.
Lessor Accounting
Sempra Infrastructure is a lessor for certain of its natural gas and ethane pipelines, compressor stations, LPG storage facilities, a rail facility and liquid fuels terminals, which we account for as operating or sales-type leases. These leases expire at various dates from 2022 through 2041.
Over the lease term, we monitor the underlying assets in operating leases for impairment, and we evaluate the net investment in sales-type leases for expected credit losses. Sempra Infrastructure expects to continue to derive value from the underlying assets associated with its pipelines following the end of their respective lease terms based on the expected remaining useful life, expected market conditions and plans to re-market and re-contract the underlying assets.
Generally, we recognize operating lease income on a straight-line basis over the lease term, and sales-type lease income based on the effective interest method over the lease term. Certain of our leases contain rate adjustments or are based on foreign currency exchange rates that may result in lease payments received that vary in amount from one period to the next.
In July 2021, a rail facility agreement commenced, which Sempra Infrastructure is accounting for as a sales-type lease. The rail facility is being used by the lessee to transport liquid fuels out of the Veracruz terminal. The lessee has the right to direct the use of the rail facility and will obtain substantially all of the economic benefits of the rail facility. At lease commencement, Sempra Infrastructure derecognized the $44 million carrying value of the rail facility from PP&E and recognized a net investment in sales-type lease asset of $62 million and a selling profit of $18 million. The agreement expires in 2041 and will automatically renew for successive five-year terms unless written notice is provided by Sempra Infrastructure or the lessee. Fixed lease payments are payable in the first five years of the agreement, which the lessee is required to pay even in the event of lease termination.
(1) Included in Machinery and Equipment - Pipelines and Storage within the major functional categories of PP&E.
(2) Includes $9 in Other Current Assets and $46 in Other Long-Term Assets on the Consolidated Balance Sheet.
(1) Included in Revenues: Energy-Related Businesses on the Consolidated Statements of Operations.
CONTRACTUAL COMMITMENTS
Natural Gas Contracts
SoCalGas has responsibility for procuring natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas buys natural gas under short-term and long-term contracts for this portfolio from various producing regions in the southwestern U.S., U.S. Rockies and Canada. At December 31, 2021, SoCalGas’ natural gas purchase commitments under long-term contracts are negligible.
SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2032.
Sempra Infrastructure has various capacity agreements for natural gas storage and transportation that expire at various dates through 2059. Transportation costs on these agreements vary based on pipeline capacity.
Payments on our natural gas contracts could exceed the minimum commitment based on portfolio needs. At December 31, 2021, the future minimum payments under existing natural gas contracts and natural gas storage and transportation contracts are as follows:
(1) Excludes amounts related to the LNG purchase agreement discussed below.
Total payments under natural gas contracts and natural gas storage and transportation contracts as well as payments to meet additional portfolio needs at Sempra and SoCalGas were as follows:
LNG Purchase Agreement
Sempra Infrastructure has a sale and purchase agreement for the supply of LNG to the ECA Regas Facility. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2022 to 2029. Although this agreement specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the agreement by Sempra Infrastructure.
At December 31, 2021, the following LNG commitment amounts are based on the assumption that all LNG cargoes, less those already confirmed to be diverted, under the agreement are delivered:
Actual LNG purchases were approximately $27 million in 2021, $16 million in 2020 and $17 million in 2019 due to the customer electing to divert cargoes as allowed by the agreement.
Purchased-Power Contracts
For 2022, SDG&E expects to meet its customer power requirements from the following resource types:
▪Long-term contracts: 60% (of which 57% is provided by renewable energy contracts expiring on various dates through 2042)
▪Other SDG&E-owned generation and tolling contracts expiring on various dates through 2039: 46%
▪Spot market sales: (6)%
Payments on our purchased-power contracts could exceed the minimum commitments based on energy needs. At December 31, 2021, the future minimum payments under long-term purchased-power contracts for Sempra and SDG&E are as follows:
(1) Excludes purchase agreements accounted for as operating leases and finance leases.
Payments on these contracts represent capacity charges and minimum energy and transmission purchases that exceed the minimum commitment. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. SDG&E estimates these variable payments to be $63 million in each of 2022 through 2026 and $430 million thereafter. Total payments under purchased-power contracts for Sempra and SDG&E were $495 million in 2021, $534 million in 2020 and $744 million in 2019.
Construction and Development Projects
Sempra has various capital projects in progress in the U.S. and Mexico. Our total contractual commitments at December 31, 2021 under these projects are approximately $389 million, requiring future payments of $223 million in 2022, $22 million in 2023, $18 million in each of 2024 and 2025, $5 million in 2026 and $103 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to such projects.
SDG&E
At December 31, 2021, SDG&E has commitments to make future payments of $27 million for construction projects that include:
▪$4 million for infrastructure improvements for electric and natural gas transmission and distribution systems; and
▪$23 million related to spent fuel management at SONGS.
SDG&E expects future payments under these contractual commitments to be $3 million in each of 2022 and 2023, $1 million in each of 2024 through 2026 and $18 million thereafter.
Sempra Infrastructure
At December 31, 2021, Sempra Infrastructure has commitments to make future payments of $362 million for construction and development projects that include:
▪$43 million for liquid fuels terminals;
▪$296 million for natural gas pipelines and ongoing maintenance services; and
▪$23 million for renewables projects.
Sempra Infrastructure expects future payments under these contractual commitments to be $220 million in 2022, $19 million in 2023, $17 million in each of 2024 and 2025, $4 million in 2026 and $85 million thereafter.
OTHER COMMITMENTS
SDG&E
We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 15.
Fire Mitigation Fund
In connection with the completion of the Sunrise Powerlink project in 2012, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments, for which a liability has been recorded, are expected
to be $4 million per year in 2022 through 2026 and $275 million thereafter, subject to escalation of 2% per year, for a remaining 48-year period. At December 31, 2021, the present value of these future payments of $122 million has been recorded as a regulatory asset as the amounts represent a cost that we expect will be recovered from customers in the future.
Franchise Agreements
In December 2020, the City of San Diego and SDG&E agreed to extend SDG&E’s natural gas and electric franchises for the city to June 1, 2021. After completing a competitive bid process, on June 8, 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. Over the 20-year term of the agreements, SDG&E will make principal payments of $110 million and interest payments of $13 million as consideration for the natural gas and electric franchise agreements. The consideration paid will not be recovered from customers and will be amortized over 20 years. SDG&E paid $11 million to the City of San Diego in 2021. At December 31, 2021, SDG&E has commitments to make future payments of $14 million per year in 2022 through 2024, $15 million in 2025, $4 million in 2026 and $51 million thereafter.
Two lawsuits have been filed in the California Superior Court challenging the City’s process for its award of the natural gas and electric franchises and seeking to declare the franchise agreements null and void.
Sempra Infrastructure
Additional consideration for a 2006 comprehensive legal settlement with the State of California to resolve the Continental Forge litigation included an agreement that, for a period of 18 years beginning in 2011, Sempra Infrastructure would sell to SDG&E and SoCalGas, subject to annual CPUC approval, up to 500 MMcf per day of regasified LNG from Sempra Infrastructure’s ECA Regas Facility that is not delivered or sold in Mexico at the price indexed to the California border minus $0.02 per MMBtu. There are no specified minimums required, and to date, Sempra Infrastructure has not been required to deliver any natural gas pursuant to this agreement.
ENVIRONMENTAL ISSUES
Our operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a PRP under the federal Superfund laws and similar state laws.
In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide emissions could result in requirements for additional pollution control equipment or significant emissions fees or taxes that could adversely affect Sempra Infrastructure. SDG&E’s and SoCalGas’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates.
We disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions, exclusive of interest and costs, exceed the lesser of $1 million or 1% of current assets, which was $44 million for Sempra, $14 million for SDG&E and $16 million for SoCalGas at December 31, 2021.
We discuss environmental matters related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility above in “Legal Proceedings - SoCalGas - Aliso Canyon Natural Gas Storage Facility Gas Leak.”
Other Environmental Issues
We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:
We have not identified any significant environmental issues outside the U.S.
At SDG&E and SoCalGas, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.
The environmental issues currently facing us, except for those related to the Leak as we discuss above or resolved during the last three years, include (1) investigation and remediation of SDG&E’s and SoCalGas’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by SDG&E and SoCalGas at which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.
The table below shows the status at December 31, 2021 of SDG&E’s and SoCalGas’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:
(1) There may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.
We record environmental liabilities when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanups proceed, we make adjustments as necessary.
The following table shows our accrued liabilities for environmental matters at December 31, 2021. Of the total liability, $9 million at SoCalGas is recorded on a discounted basis, with a discount rate of 1.5%.
(1) Sites for which we have been identified as a PRP.
(2) Includes $5, $2 and $3 classified as current liabilities, and $52, $16 and $35 classified as noncurrent liabilities on Sempra’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.
(3) Does not include SDG&E’s liability for SONGS marine environment mitigation.
(4) Does not include SoCalGas’ liability for environmental matters for the Leak. We discuss matters related to the Leak above in “Legal Proceedings - SoCalGas - Aliso Canyon Natural Gas Storage Facility Gas Leak.”
In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the CCC to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 15, does not reduce SDG&E’s mitigation obligation. SDG&E’s share of the estimated mitigation costs is $97 million, of which $53 million has been incurred through December 31, 2021 and $44 million is accrued for remaining costs through 2053, which is recoverable in rates and included in noncurrent Regulatory Assets on Sempra’s and SDG&E’s Consolidated Balance Sheets.
We expect future payments related to our environmental liabilities on an undiscounted basis to be $6 million in 2022, $13 million in 2023, $9 million in 2024, $4 million in 2025, $17 million in 2026 and $53 million thereafter.
NOTE 17. SEGMENT INFORMATION
We have four separately managed reportable segments, as follows:
▪SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
▪SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
▪Sempra Texas Utilities holds our investment in Oncor Holdings, which owns an 80.25% interest in Oncor, a regulated electric transmission and distribution utility serving customers in the north-central, eastern, western and panhandle regions of Texas; and our indirect, 50% interest in Sharyland Holdings, which owns Sharyland Utilities, a regulated electric transmission utility serving customers near the Texas-Mexico border.
▪Sempra Infrastructure 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. Sempra Infrastructure owns an 80% interest in SI Partners, which held a 100% ownership interest in Sempra LNG Holding, LP and a 99.9% ownership interest in IEnova at December 31, 2021.
In April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments. Upon completion of this sale, remaining nominal business activities at Sempra Renewables were subsumed into Parent and other and the Sempra Renewables segment ceased to exist. The tables below include amounts from Sempra Renewables up until cessation of the segment.
As we discuss in Note 5, the financial information related to our businesses that constituted the Sempra South American Utilities segment is presented as discontinued operations for all periods presented. The information in the tables below excludes amounts from discontinued operations unless otherwise noted. We completed the sales of our discontinued operations in the second quarter of 2020.
We evaluate each segment’s performance based on its contribution to Sempra’s reported earnings and cash flows. SDG&E and SoCalGas operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC and, in the case of SDG&E, the FERC. We describe the accounting policies of all of our segments in Note 1.
The cost of common services shared by the business segments is assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.
The following tables show selected information by segment from our Consolidated Statements of Operations and Consolidated Balance Sheets. We provide information about our equity method investments by segment in Note 6. Amounts labeled as “All other” in the following tables consist primarily of activities of parent organizations and include certain nominal amounts from our South American businesses that did not qualify for treatment as discontinued operations.
(1)Revenues for reportable segments include intersegment revenues of $10, $98, and $55 for 2021; $5, $88, and $(3) for 2020; and $5, $69, and $11 for 2019 for SDG&E, SoCalGas, and Sempra Infrastructure, respectively.
(2)Includes net PP&E and investments.
(3)Amounts are based on where the revenue originated, after intercompany eliminations.
SCHEDULE I - SEMPRA ENERGY
INDEX TO CONDENSED FINANCIAL INFORMATION OF PARENT
Condensed Statements of Operations for the years ended December 31, 2021, 2020 and 2019
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Condensed Statements of Comprehensive Income (Loss) for the years ended December 31, 2021, 2020 and 2019
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Condensed Balance Sheets at December 31, 2021, 2020 and 2019
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Condensed Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019
S-5
Notes to Condensed Financial Information of Parent
Note 1. Basis of Presentation
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Note 2. New Accounting Standards
S-6
Note 3. Debt and Credit Facility
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Note 4. Commitments and Contingencies
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S-1
See Notes to Condensed Financial Information of Parent.
S-2
See Notes to Condensed Financial Information of Parent.
S-3
See Notes to Condensed Financial Information of Parent.
S-4
See Notes to Condensed Financial Information of Parent.
S-5
NOTES TO CONDENSED FINANCIAL INFORMATION OF PARENT
NOTE 1. BASIS OF PRESENTATION
The condensed financial information of Sempra Energy has been prepared in accordance with SEC Regulation S-X Rule 5-04 and Rule 12-04. We apply the same accounting policies as in the financial statements of Sempra, except that Sempra Energy accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information.
Sempra Energy received cash dividends from its consolidated subsidiaries totaling $375 million, $300 million and $150 million in 2021, 2020 and 2019, respectively.
NOTE 2. NEW ACCOUNTING STANDARDS
We describe below and in Note 2 of the Notes to Consolidated Financial Statements recent pronouncements that have had or may have a significant effect on Sempra Energy’s results of operations, financial condition, cash flows or disclosures.
ASU 2020-06, “Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity”: ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. In addition to other changes, this standard amends ASC 470-20, “Debt with Conversion and Other Options,” by removing the accounting models for instruments with beneficial and cash conversion features. The standard also amends certain guidance in ASC 260, “Earnings Per Share,” for the computation of EPS for convertible instruments and contracts on an entity’s own equity. For public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. An entity can use either a full or modified retrospective approach to adopt ASU 2020-06 and must disclose, in the period of adoption, EPS transition information about the effect of the change on affected per-share amounts. We will adopt the standard on January 1, 2022 using a modified retrospective approach and do not expect the adoption will materially impact our financial statements or per-share amounts.
NOTE 3. DEBT AND CREDIT FACILITY
SHORT-TERM DEBT
Committed Line of Credit
At December 31, 2021, Sempra Energy had an aggregate capacity of $4.4 billion under two primary committed lines of credit and available unused credit of $3.1 billion, which provide liquidity and support its commercial paper program. The amount of commercial paper outstanding, before reduction of any unamortized discount, and any letters of credit outstanding is reflected as a reduction to the available unused credit.
The principal terms of Sempra Energy’s committed lines of credit include the following:
▪Each facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in the facility.
▪One facility provides for the issuance of $200 million of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra Energy has the right to increase its letter of credit commitment to $500 million. No letters of credit were outstanding at December 31, 2021.
▪Borrowings bear interest at a benchmark rate plus a margin that varies with Sempra Energy’s credit rating.
▪Sempra Energy must maintain a ratio of indebtedness to total capitalization (as defined in its credit facility) of no more than 65% at the end of each quarter. At December 31, 2021, Sempra Energy was in compliance with this ratio under credit facility.
S-6
LONG-TERM DEBT
The following table shows the detail and maturities of long-term debt outstanding:
(1) Callable long-term debt not subject to make-whole provisions.
In December 2021, Sempra Energy 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 November 2021, we issued $1.0 billion of 4.125% fixed-to-fixed reset rate junior subordinated notes maturing on April 1, 2052. Interest on the notes accrues from and including November 19, 2021 and is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on April 1, 2022. The notes will bear interest (i) from and including November 19, 2021 to, but excluding, April 1, 2027 at the rate of 4.125% per annum and (ii) from and including April 1, 2027, during each subsequent five-year period beginning on April 1 of every fifth year, at a rate per annum equal to the Five-year U.S. Treasury Rate (as defined in the notes) as of the day falling two business days before the first day of such five-year period plus a spread of 2.868%, to be reset on April 1 of every fifth year beginning in 2027. We received proceeds of $988 million (net of underwriting discounts and debt issuance costs of $12 million). We used the proceeds from the offering to repay a portion of the aggregate principal amount of the $2.35 billion of senior unsecured notes that we discuss above.
At December 31, 2021, long-term debt maturities totaling $6.1 billion commence after 2026.
Additional information on Sempra Energy’s long-term debt is provided in Note 7 of the Notes to Consolidated Financial Statements.
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NOTE 4. COMMITMENTS AND CONTINGENCIES
Sempra Energy has an operating lease commitment related to its corporate headquarters building of approximately $279 million. Sempra Energy expects payments for its operating lease to be $11 million in 2022, $12 million in each of 2023 through 2026 and $220 million thereafter.
For other contingencies and guarantees related to Sempra Energy, refer to Notes 6 and 16 of the Notes to Consolidated Financial Statements.
S-8

Market Capitalization: 45167026.05963135
1-Year Return: 0.05371382832527161
252-Day Return: $252_day_return