ITEM 1. BUSINESS
This report on Form 10-K includes information for the following separate registrants:
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Sempra Energy and its consolidated entities
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SDG&E and its consolidated VIE (until deconsolidation of the VIE on August 23, 2019)
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SoCalGas
References in this report to “we,” “our,” “us,” “our company” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include Sempra Texas Utilities or the utility in our Sempra Mexico segment.
OVERVIEW
We are a California-based energy-services holding company. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers in North America. Sempra Energy 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 2018 and 2020 acquisitions of an aggregate indirect 80.45% interest in Oncor and, in 2019, Oncor’s acquisition of InfraREIT and our acquisition of an indirect 50% interest in Sharyland Utilities. Since 1995, we have had a strong and growing presence in Mexico through IEnova, the first energy infrastructure company to be listed on the Mexican Stock Exchange. IEnova has a diverse portfolio of projects and assets serving Mexico’s growing energy needs. Our energy infrastructure footprint continues to expand across North America, through LNG development projects and assets in Louisiana, Texas and Mexico, including our indirect 50.2% interest in Cameron LNG JV, which commenced commercial operation of the first of three liquefaction trains in August 2019.
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 entering into agreements to sell our South American businesses. We expect to complete the sales of our South American businesses in the first half of 2020. 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 focused on generating stable, predictable earnings and cash flows by investing in, developing and operating electric and gas infrastructure with the goal of delivering safe and reliable energy to our customers and increasing shareholder value.
DESCRIPTION OF BUSINESS BY SEGMENT
We operate our business through the following reportable segments:
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SDG&E
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SoCalGas
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Sempra Texas Utilities
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Sempra Mexico
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Sempra Renewables (until April 2019)
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Sempra LNG
SDG&E
SDG&E is a regulated public utility that provides electric services to a population of approximately 3.7 million and natural gas services to approximately 3.4 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 southern Orange County.
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 San Diego, Imperial and Orange counties of California, and in Arizona and Nevada and consist of 2,099 miles of transmission lines, 23,562 miles of distribution lines and 161 substations as of December 31, 2019. Periodically, various areas of the service territory require expansion to accommodate customer growth, 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 408 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 a spot basis. SDG&E does not earn any return on commodity sales volumes. SDG&E’s supply as of December 31, 2019 was as follows:
(1)
Excludes approximately 107.5 MW of battery storage owned and approximately 9.5 MW of battery 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.
SDG&E is required to interconnect with and purchase power from QFs, a class of generating facilities established by the Public Utility Regulatory Policies Act of 1978, at rates that do not exceed SDG&E’s avoided cost. SDG&E’s QFs include cogeneration facilities, which produce electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, residential or institutional purposes. Charges under most of the contracts with QFs are based on what it would incrementally cost SDG&E to produce the power or procure it from other sources. Charges under the contracts with other suppliers are for firm and as-generated energy and 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. The prices under these contracts include 125 MW at prices that are based on the market value at the time the contracts were negotiated.
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.
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. As of December 31, 2019, 2018 and 2017, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 1,233 MW, 1,023 MW and 836 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 rooftop solar installations and battery storage, and the corresponding decrease in demand for power from departing retail load from customers transferring to load serving entities other than SDG&E. While SDG&E currently provides procurement service for the majority of its customer load, customers do have the ability to receive procurement service from a load serving entity other than SDG&E through programs such as DA and CCA. DA is currently limited by a cap based on gigawatt hours. Utility customers can also receive procurement through CCA, if the customer’s local jurisdiction (city) offers such a program. Several local political jurisdictions, including the City of San Diego and other municipalities, are considering implementing or are implementing a CCA, which could result in SDG&E providing procurement service for less than half of its current customer load as early as 2021. When customers are served by another load serving entity, SDG&E no longer procures electricity for this departing load and 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 are served by DA or CCA), the CPUC revised the Power Charge Indifference Adjustment framework by adopting several refinements, which SDG&E implemented on January 1, 2019.
Natural Gas Utility Operations
We describe SDG&E’s natural gas utility operations below in “California Utilities’ Natural Gas Utility Operations.”
Key Noncash Performance Indicators
We use certain financial and non-financial metrics to measure how effective our businesses are in achieving their key business objectives. SDG&E’s key noncash performance indicators include goals related to safety (including activities designed to help reduce the risk of wildfires), number of customers, electricity sold, system average rate and natural gas volumes transported and sold. Additional noncash performance indicators include customer service, company reputation, environmental considerations (including quantities of renewable energy purchases), on-time and on-budget completion of major projects and initiatives, and service reliability.
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 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).
Natural Gas Utility Operations
We describe SoCalGas’ natural gas utility operations below in “California Utilities’ Natural Gas Utility Operations.”
Key Noncash Performance Indicators
Key noncash performance indicators for SoCalGas include goals related to safety, number of customers and natural gas volumes transported and sold. Additional noncash performance indicators include customer service, company reputation, environmental considerations, natural gas demand by customer segment, on-time and on-budget completion of major projects and initiatives, and service reliability.
California Utilities’ Natural Gas Utility Operations
Natural Gas Procurement and Transportation
At December 31, 2019, SoCalGas’ natural gas facilities include 3,058 miles of transmission and storage pipelines, 51,073 miles of distribution pipelines, 48,315 miles of service pipelines and nine transmission compressor stations, while SDG&E’s natural gas facilities consist of 168 miles of transmission pipelines, 8,961 miles of distribution pipelines, 6,582 miles of service pipelines and one compressor station.
SoCalGas purchases natural gas under short-term and long-term contracts for the California Utilities’ 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 help ensure the delivery of natural gas supplies to its distribution system and to meet the seasonal and annual 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 or its transportation customers from outside of California.
Natural Gas Storage
SoCalGas owns four natural gas storage facilities with a combined working gas capacity of 137 Bcf and over 200 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 offers the remaining storage capacity for sale to others, including SDG&E for its non-core customer requirements. Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including 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, as of July 2018, has been directed by the CPUC to maintain up to 34 Bcf of working gas to help achieve reliability for the region at reasonable rates as determined by the CPUC. In July 2019, to maintain system reliability and price stability, the CPUC issued a protocol authorizing withdrawals of natural gas from the facility if gas
supply is low in the region. We discuss the Aliso Canyon natural gas storage facility leak in Note 16 of the Notes to Consolidated Financial Statements, in “Item 1A.
ITEM 1A. RISK FACTORS
When evaluating our company and its subsidiaries, you should consider carefully the following risk factors and all other information contained in this report. These risk factors could materially adversely affect our actual results and cause such results to differ materially from those expressed in any forward-looking statements made by us or on our behalf. We may also be materially harmed by risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of the following occurs, our businesses, cash flows, results of operations, financial condition and/or prospects could be materially adversely affected. In addition, the trading prices of our securities and those of our subsidiaries could substantially decline due to the occurrence of any of these risks. These risk factors should be read in conjunction with the other detailed information concerning our company set forth in, or attached as an exhibit to, this annual report on Form 10-K, including, without limitation, the information set forth in the Notes to Consolidated Financial Statements and in “Item 7. MD&A.”
Risks Related to Sempra Energy
Sempra Energy’s cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its subsidiaries and entities that are accounted for as equity method investments, such as Oncor Holdings, and the ability to utilize the cash flows from those subsidiaries and equity method investments.
We are a holding company and substantially all our assets are owned by our subsidiaries and in entities accounted for as equity method investments, such as Oncor Holdings. Our ability to pay dividends and to meet our debt and other obligations depends almost entirely on cash flows from our subsidiaries and equity method investments and, in the short term, our ability to raise capital from external sources. In the long term, cash flows from our subsidiaries and equity method investments depend on their ability to successfully execute their business strategies and generate positive cash flows. In addition, the subsidiaries and other entities accounted for as equity method investments are separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be precluded from paying any such dividends or making any such loans or distributions under certain circumstances, including, without limitation, as a result of legislation, regulation, court order, contractual restrictions or in times of financial distress. The inability to access capital from our subsidiaries and entities accounted for as equity method investments as well from the capital markets could have a material adverse effect on our cash flows, financial condition and prospects.
Conditions in the financial markets and economic conditions generally may materially adversely affect us.
Our businesses are capital intensive and we rely significantly on long-term debt to fund a portion of our capital expenditures and repay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations.
Limitations on the availability of credit and increases in interest rates or credit spreads may materially adversely affect our businesses, cash flows, results of operations, financial condition and/or prospects, as well as our ability to meet contractual and other commitments. In difficult credit market environments, we may find it necessary to fund our operations and capital expenditures at a higher cost or we may be unable to raise as much funding as we need to support new or ongoing business activities. This could cause us to reduce non-safety related capital expenditures and could increase our cost of servicing debt, both of which could significantly reduce our short-term and long-term profitability.
Other factors can affect the availability and cost of credit for our businesses as well as the terms of equity and debt financing, including:
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adverse changes to laws and regulations in the states and countries in which we operate
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the overall health of the energy industry
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volatility in natural gas or electricity prices
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credit ratings downgrades
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general economic and financial market conditions
In addition, over the past several years, California IOUs have suffered from the potential catastrophic losses resulting from the impact of the multiple wildfires that spread through Northern and Southern California (the California Wildfires). While the California Wildfires occurred in counties outside of SDG&E’s electric service territory, the uncertainty about the outcomes of these matters, the possibility of catastrophic wildfires in the future and the failure of the State of California to adequately address the financial and operational risks facing California IOUs could materially and adversely impact Sempra Energy’s and the California Utilities’ ability to access the capital markets at rates that we believe are commercially reasonable.
We are subject to additional risk due to uncertainty relating to the calculation of LIBOR and its potential discontinuance.
Certain of our financial and commercial agreements, including variable rate indebtedness and credit facilities, as well as interest rate derivatives, incorporate LIBOR as a benchmark for establishing certain rates. LIBOR is the subject of recent national, international and other regulatory guidance and proposals for reform, including discontinuation or replacement. These reforms, if implemented, will cause this benchmark to perform differently than it has performed in the past or to be discontinued entirely or may have other consequences that cannot be predicted, which could have a material adverse effect on our financial condition or results of operations or require us to seek to amend the terms of the relevant indebtedness or agreements, which may require significant additional time, effort and/or money in the form of consent payments or otherwise, and may not be possible on comparable terms or at all.
In an announcement on July 12, 2018, the Financial Conduct Authority in the United Kingdom, which regulates LIBOR, emphasized the need for market participants to transition away from LIBOR before the end of 2021. It appears likely that LIBOR will be discontinued or replaced with a different benchmark rate by 2021. A number of alternatives to LIBOR have been proposed or are being developed, but it is not clear which, if any, will be adopted at this time. Any of these alternatives 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 on such indebtedness for the interest periods if the applicable LIBOR rate was available in its current form. More generally, any of the foregoing changes, any other changes to LIBOR as a result of national, international and other regulatory guidance and proposals for reform or other initiatives, or any further uncertainty surrounding the implementation of such changes, could have a material adverse effect on the cost of our variable rate indebtedness and/or borrowings, the effectiveness of our cash flow hedges and the cost of doing business under our commercial agreements that incorporate LIBOR.
Sempra Energy has substantial investments in Mexico and South America that expose us to foreign currency, inflation, legal, tax, economic, geopolitical and management oversight risk.
We have significant foreign operations in Mexico and South America. Our foreign operations pose complex management, foreign currency, inflation, legal, tax and economic risks. Certain of these risks differ from and potentially may be greater than those associated with our domestic businesses. All our international businesses are sensitive to geo-political uncertainties and our non-utility international businesses are sensitive to changes in the priorities and budgets of international customers, all of which may be driven by changes in their environments and potentially volatile worldwide economic conditions, and various regional and local economic and political factors, risks and uncertainties, as well as U.S. foreign policy. Foreign currency exchange and inflation rates and fluctuations in those rates may have an impact on our revenue, costs or cash flows from our international operations, which could materially adversely affect our financial performance. Our currency exposures are to the Mexican, Peruvian and Chilean currencies. Our Mexican subsidiary, IEnova, has U.S. dollar-denominated monetary assets and liabilities that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have significant deferred income tax assets and liabilities, which are denominated in the Mexican peso and 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. Our primary objective when we attempt to reduce foreign currency risk is to preserve the economic value of our foreign investments and to reduce earnings volatility that would otherwise occur due to exchange rate fluctuations. We may attempt to hedge material cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments. We generally do not hedge our deferred income tax assets and liabilities. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations, primarily related to our South American subsidiaries, whose functional currencies are not the U.S.
dollar. We discuss our foreign currency exposure at our Mexican subsidiaries in “Item 7. MD&A” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
The current U.S. administration has called for substantial changes to trade agreements. For example, in November 2018, President Trump signed the USMCA, which, if approved by the legislatures of the U.S., Mexico and Canada, would replace NAFTA. The U.S. and Mexico approved the USMCA in January 2020 and June 2019, respectively, but Canada has yet to provide its approval. The U.S. administration has also implemented changes to U.S. immigration policy and other policies that could impact trade, including increasing tariffs. Such actions could result in changes in the Mexican, U.S. and other markets that could materially adversely affect our business, financial condition, results of operations, cash flows or prospects. In addition, if the U.S. withdraws from NAFTA, the Mexican government could implement retaliatory actions, such as the imposition of restrictions or import fees on Mexican imports of natural gas from the U.S. or imports and exports of electricity to and from the U.S. Any of these actions by either or both governments could adversely affect imports and exports between Mexico and the U.S. and negatively impact the U.S. and Mexican economies and the companies with whom we conduct business in Mexico, which could materially adversely affect our business, financial condition, results of operations, cash flows, or prospects.
We may be unable to realize the anticipated benefits from our plan to divest certain of our assets and businesses as part of our capital rotation plan.
In 2019, we completed the divestiture of all our U.S. solar and wind assets and certain non-utility natural gas storage assets in the southeast U.S. Additionally, we entered into agreements to sell our South American businesses, which we expect to close in the first half of 2020, subject to a number of closing conditions. There can be no assurance that the pending sales will be completed. If we do not successfully manage our current capital rotation plan, any expected efficiencies and benefits might be delayed or not realized, and our results of operations and business could be materially adversely affected.
The TCJA may materially adversely affect our financial condition, results of operations and cash flows, the value of investments in our common stock, preferred stock and debt securities.
The TCJA significantly changed the IRC, including taxation of U.S. corporations by, among other things, reducing the U.S. corporate income tax rate, altering the expensing of capital expenditures, limiting interest deductions, adopting elements of a territorial tax system, assessing a one-time deemed repatriation tax on cumulative undistributed earnings of U.S.-owned foreign entities at the time of enactment and introducing certain anti-base erosion provisions. While the U.S Department of the Treasury has issued final regulations for various sections of the IRC, certain aspects of the legislation are still subject to interpretation and will require implementing regulations by the U.S. Department of the Treasury, as well as state tax authorities, which could lessen or increase adverse impacts. In addition, the regulatory treatment of the impacts of this legislation may be subject to the discretion of the FERC and state public utility commissions.
Although it is unclear when or how capital markets, the FERC or state public utility commissions may respond to the TCJA, we expect that certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, will be negatively impacted as a result of an anticipated decrease in required income tax reimbursement payments to us from our domestic utility subsidiaries due to the decrease in the U.S. statutory corporate income tax rate. Certain provisions of the TCJA, such as 100% expensing of certain capital expenditures and impacts on utilization of our NOLs, may influence how we fund capital expenditures, the timing of capital expenditures and possible redeployment of capital through sales or monetization of assets, the timing of repatriation of foreign earnings and the use of equity financing to reduce our future use of debt, although there can be no assurance that these strategies will reduce any potential adverse impact from these provisions of the TCJA. In addition, although the deductibility of our interest cost is not limited for the current year, future earnings may be affected based on our method of allocation across our businesses.
It is also uncertain whether additional avenues will evolve for companies to manage the adverse aspects of this legislation. We believe that these strategies, to the extent available and if successfully applied, could lessen any such negative impacts on us, although there can be no assurance in this regard.
We discuss the effects of the TCJA further in Note 8 of the Notes to Consolidated Financial Statements and in “Item 7. MD&A - Results of Operations.”
Our mandatory convertible preferred stock, as well as any additional equity securities we may sell to raise funds, may dilute the economic and voting interests of our common shareholders and may adversely affect the market value of our common stock.
In January 2018, we issued 17,250,000 shares of our series A preferred stock, and in July 2018, we issued 5,750,000 shares of our series B preferred stock, which are scheduled to convert into common stock on January 15, 2021 and July 15, 2021, respectively. We may seek to reduce our indebtedness with the proceeds from the issuance of additional shares of common stock and, possibly,
other equity securities, which, together with the conversion of the series A preferred stock and series B preferred stock, may materially dilute the voting rights and economic interests of holders of our common stock and materially adversely affect the trading price of our common stock.
Our level of indebtedness may make it more difficult for us to pay or refinance our debts or take other actions, and we may need to divert cash to fund debt service payments or issue additional equity that may materially dilute the voting rights and economic interest of holders of our common stock.
Our substantial debt service obligations due to our aggregate indebtedness could have a material adverse effect on Sempra Energy’s results of operations, cash flows, financial condition and prospects by, among other things:
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making it more difficult and/or costly for us to service our debt or pay or refinance our debts as they become due, particularly during adverse economic or industry conditions;
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limiting our flexibility to pursue other strategic opportunities or react to changes in our business and the industry sectors in which we operate;
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requiring a substantial portion of our available cash to be used for debt service payments, including interest, thereby reducing the availability of our cash to fund working capital, capital expenditures, development projects, acquisitions, dividend payments and other general corporate purposes, which could hinder our prospects for growth and the market price of our common stock, preferred stock and debt securities, among other things;
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requiring that additional materially adverse terms, conditions or covenants be placed on us under our debt instruments, which covenants might limit additional borrowings; and
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imposing specific restrictions on uses of our assets, as well as prohibiting or limiting our ability to create liens, pay dividends, receive distributions from our subsidiaries, redeem or repurchase our stock or make investments, any of which could hinder our access to capital markets and limit our ability to carry out our capital expenditure program.
We are committed to maintaining our credit ratings at investment grade. To maintain these credit ratings, we may reduce the amount of our outstanding indebtedness with the proceeds from the issuance of additional shares of common stock or other equity securities. Additional equity issuances may dilute the voting rights and economic interests of holders of our common stock. There can be no assurance that we will be able to issue additional shares of our common stock or other equity securities with terms that we consider acceptable or at all, or that we will be able to reduce the amount of our outstanding indebtedness, should we elect to do so, to a level that allows us to maintain our investment grade credit ratings, which may have a material adverse effect on Sempra Energy’s cash flows, financial condition, results of operations and/or prospects.
Certain credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook.
Credit rating agencies routinely evaluate Sempra Energy and the California Utilities, and their ratings are based on a number of factors, including the increased risk of wildfires in California, perceived supportiveness of the regulatory environment affecting utility operations, including delays and difficulties in obtaining recovery, or the denial of recovery, for wildfire-related costs, ability to generate cash flows, level of indebtedness, overall financial strength, including credit metrics, diversification beyond the regulated utility business (in the case of Sempra Energy), and the status of certain capital projects, as well as other factors beyond our control, such as the state of the economy and our industry generally. Downgrades and factors causing downgrades of one or both of the California Utilities can have a material impact on Sempra Energy’s credit ratings. Downgrades, as well as the factors causing such downgrades, of Sempra Energy’s credit ratings could imply diminished credit support available to our subsidiaries. Accordingly, downgrades of Sempra Energy’s credit ratings can also have a material impact on the credit ratings of our subsidiaries, including the California Utilities.
While the current Moody’s, S&P and Fitch (collectively, the Rating Agencies) issuer credit ratings for Sempra Energy, SDG&E and SoCalGas are investment grade, there is no assurance that these credit ratings will not be downgraded.
For Sempra Energy, the Rating Agencies have noted that the following events, among other things, could lead to negative ratings actions:
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delays at the Cameron LNG project and the impact on financial credit metrics;
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construction of LNG liquefaction projects and the impact on business mix and financial credit metrics over time;
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Sempra Energy’s failure to meet certain financial credit metrics;
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the CPUC does not effectively implement the more supportive prudency standard associated with the Wildfire Legislation; or
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a ratings downgrade at SDG&E and/or SoCalGas.
For SDG&E, the Rating Agencies have noted that the following events, among other things, could lead to negative ratings actions:
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the CPUC does not effectively implement the more supportive prudency standard associated with the Wildfire Legislation;
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a consistent weakening of SDG&E’s financial metrics;
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catastrophic wildfires caused by California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably earlier than expected; or
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a ratings downgrade at Sempra Energy.
For SoCalGas, the Rating Agencies have noted that the following events, among other things, could lead to negative ratings actions:
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SoCalGas’ credit metrics do not improve materially after implementation of the GRC and cost of capital decisions finalized in 2019;
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SoCalGas experiences increased business risk, weakening its standalone business risk profile;
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deterioration of, or uncertainty in, the political or regulatory environment for local natural gas distribution companies operating in California; or
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a ratings downgrade at Sempra Energy.
A downgrade of Sempra Energy’s or either of its California Utilities’ credit ratings may materially and adversely affect the market prices of Sempra Energy’s equity and debt securities, the interest rates at which borrowings are made and debt securities and commercial paper are issued, and the various fees on credit facilities. This could make it significantly more costly for Sempra Energy, SDG&E, SoCalGas and Sempra Energy’s other subsidiaries to borrow money, to issue debt securities and to raise certain other types of capital and/or complete additional financings. Such negative credit rating actions, as well as the reasons for such actions could materially and adversely affect our cash flows, results of operations and financial condition and the market price of, and our ability to pay the principal of and interest on, our debt securities.
Dividend requirements associated with our mandatory convertible preferred stock subject us to certain risks.
In January 2018, we issued 17,250,000 shares of our series A preferred stock, and in July 2018, we issued 5,750,000 shares of our series B preferred stock. Any future payments of cash dividends, and the amount of any cash dividends we pay, on our series A preferred stock and our series B preferred stock will depend on, among other things, our financial condition, capital requirements and results of operations, and the ability of our subsidiaries and equity method investees to distribute cash to us, as well as other factors that our board of directors may consider relevant. Any failure to pay scheduled dividends on our mandatory convertible preferred stock when due would have a material adverse impact on the market price of our mandatory convertible preferred stock, our common stock and our debt securities and would prohibit us, under the terms of our mandatory convertible preferred stock, from paying cash dividends on or repurchasing shares of our common stock (subject to limited exceptions) until such time as we have paid all accumulated and unpaid dividends on the mandatory convertible preferred stock.
The terms of the series A preferred stock and series B preferred stock generally provide that if dividends on any shares of the mandatory convertible preferred stock have not been declared and paid for the equivalent of six or more dividend periods, whether or not for consecutive dividend periods, the holders of shares of mandatory convertible preferred stock, voting together as a single class, will be entitled to elect a total of two additional members of our board of directors, subject to certain terms and limitations described in the certificate of determination applicable to the mandatory convertible preferred stock.
Our business could be negatively affected as a result of actions of activist shareholders.
While we strive to maintain constructive, ongoing communications with all our shareholders, and welcome their views and opinions with the goal of enhancing value for all our shareholders, activist shareholders may, from time to time, engage in proxy solicitations or advance shareholder proposals, or otherwise attempt to effect changes and assert influence on our board of directors and management. Responding to proposals by activist shareholders would require us to incur significant legal and advisory fees, proxy solicitation expenses (in the case of a proxy contest) and administrative and associated costs and require significant time and attention by our board of directors and management, diverting their attention from the pursuit of our business strategy.
Any perceived uncertainties as to our future direction and control, our ability to execute on our strategy, or changes to the composition of our board of directors or senior management team arising from proposals by activist shareholders or a proxy contest could lead to the perception of a change in the direction of our business or instability that may be exploited by our competitors and/or other activist shareholders, result in the loss of potential 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 an adverse effect, which may be material, on our business and operating results.
Actions such as those described above could cause significant fluctuations in the trading prices of our common stock and our preferred stock, based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business.
Risks Related to All Sempra Energy Businesses
Severe weather conditions, natural disasters, pandemics, accidents, equipment failures, explosions or acts of terrorism could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects.
Like other major industrial facilities, ours may be damaged by severe weather conditions, natural disasters such as fires, earthquakes, tornadoes, hurricanes, tsunamis, floods, mudslides, accidents, equipment failures, explosions or acts of terrorism. Because we are in the business of using, storing, transporting and disposing of highly flammable and explosive materials, as well as 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, are substantially greater than the risks such incidents may pose to a typical business. The facilities and infrastructure that we own or in which we have interests that may be subject to such incidents include, but are not limited to:
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natural gas, propane and ethane pipelines, storage and compressor facilities
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electric transmission and distribution
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power generation plants, including renewable energy and natural gas-fired generation
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marine and inland ethane and liquid fuels, LNG, and LPG facilities, terminals and storage
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nuclear power facilities, nuclear fuel and nuclear waste storage facilities (through SDG&E’s 20% minority interest in SONGS, which is currently being decommissioned)
Such incidents could result in severe business disruptions, prolonged power outages, property damage, injuries or loss of life, significant decreases in revenues and earnings, and/or significant additional costs to us. 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 natural gas and electricity to our customers. Other global incidents could have similar effects to the extent they reach and impact the territories in which we operate, the customers we serve or the employees who operate our businesses. For example, the coronavirus outbreak currently affecting China and elsewhere has resulted in travel restrictions and impacts on the global economy that could affect our operations in a manner that is not presently possible to predict. Any such incident could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.
Depending on the nature and location of the facilities and infrastructure affected, any such incident also could cause catastrophic fires; natural gas, natural gas odorant, propane or ethane leaks; releases of other GHG; radioactive releases; explosions, spills or other significant damage to natural resources or property belonging to third parties; personal injuries, health impacts or fatalities; or present a nuisance to impacted communities. Any of these consequences could lead to significant claims against us. In some cases, we may be liable for damages even though we are not at fault, such as in cases where the doctrine of inverse condemnation applies. We discuss how the application of this doctrine in California imposes strict liability on a utility whose equipment is determined to be a cause of a fire (meaning the utility may be found liable regardless of fault) below under “Risks Related to the California Utilities - The Wildfire Legislation may not adequately protect SDG&E from liability from catastrophic wildfires in its service territory.” Insurance coverage may significantly increase in cost or become prohibitively expensive, may be disputed by the insurers, or may become unavailable for certain of these risks or at sufficient levels, and any insurance proceeds we receive may be insufficient to cover our losses or liabilities due to the existence of limitations, exclusions, high deductibles, failure to comply with procedural requirements, and other factors, which could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects, as well as the trading prices of our common stock, preferred stock and debt securities.
Our businesses are subject to complex government regulations and tax requirements and may be materially adversely affected by these regulations or requirements or changes thereto.
The electric power and natural gas industries are subject to complex government regulations that from time to time undergo significant changes on the federal, state and local levels. The failure to comply with these regulations could subject us to significant fines and penalties and result in the temporary or permanent shutdown of certain facilities and operations. In addition, changes to these regulations or how these regulations are interpreted may adversely affect how we conduct our business and may subject us to higher compliance costs.
Our businesses are subject to increasingly complex accounting and tax requirements, and the regulations, laws and tariffs that affect us may change in response to economic or political conditions. Compliance with these requirements could increase our operating costs. Any new tax legislation, regulations or other interpretations in the U.S. and other countries in which we operate could materially adversely affect our tax expense and/or tax balances, and changes in tax policies could materially adversely impact our business. Changes in regulations, laws and tariffs and how they are implemented and interpreted may have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.
Our operations are subject to rules relating to transactions among the California Utilities and other Sempra Energy businesses. These rules are commonly referred to as “affiliate rules,” which primarily impact commodity and commodity-related transactions. These businesses could be materially adversely affected by changes in these rules or to their interpretations, or by additional CPUC or FERC rules that further restrict our ability to sell natural gas or electricity to, or to trade with, the California Utilities and with each other. Affiliate rules also restrict these businesses from entering into any such transactions with the California Utilities. Any such restrictions on or approval requirements for transactions among affiliates could materially adversely affect the LNG facilities, natural gas pipelines, electric generation facilities, or other operations of our subsidiaries, which could have a material adverse effect on our businesses, results of operations and/or prospects.
Our businesses require numerous permits, licenses, agreements and other approvals from various federal, state, local and foreign governmental agencies, and any failure to obtain or maintain them could materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.
The acquisition, construction, expansion, ownership, maintenance and/or operation of electric generation, transmission and distribution infrastructure; natural gas, propane and ethane pipelines and distribution and storage facilities; marine and inland ethane and liquid fuels, LNG, and LPG facilities, terminals and storage; and other projects require numerous permits, licenses, rights-of-way, franchise agreements, certificates and other approvals from federal, state, local and foreign governmental agencies, including approvals and renewals of rights-of-way over indigenous tribal land. These permits, licenses, rights-of-way, franchise agreements, certificates and other approvals may be modified, rescinded or fail to be extended by one or more of the governmental agencies and authorities that oversee our businesses or as a result of litigation. For example, SoCalGas’ franchise agreements with the City of Los Angeles and Los Angeles County expire in December 2020 and June 2023, respectively. SDG&E’s franchise agreement with the City of San Diego is due to expire in January 2021. Successfully maintaining or renewing any or all of these approvals could result in higher costs. Furthermore, our permits may require compliance by our underlying customers. Failure by our customers to comply with permit requirements could result in our permits being modified, suspended or rescinded. In the event one or more of these approvals were to expire or otherwise terminate, we may be required to remove the associated assets from service, construct new assets intended to bypass the impacted area, or both, and our ability to recover higher costs associated with these events cannot be assured.
Successfully coordinating and completing expansion and construction projects requires good execution from our employees and contractors, cooperation of third parties, and the absence of litigation and regulatory delay. We may invest a significant amount of money in a major capital project prior to receiving regulatory approval. If there is a delay in obtaining required regulatory approvals, if the regulatory approval is conditioned on major changes, if we fail to obtain or maintain required approvals or to comply with applicable laws or regulations, we may be precluded from constructing or operating facilities, or if management decides not to proceed with the project, we may be unable to recover any or all amounts invested in that project, which could materially adversely affect our businesses financial condition, results of operations, cash flows and/or prospects. Further, accidents beyond our control may cause us to violate the terms of conditional use permits, causing delays in projects. Any such delay or failure to obtain or maintain necessary permits, licenses, certificates and other approvals could cause our operations and prospects to materially decline, and/or our costs to materially increase, and otherwise materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.
Our businesses have significant environmental compliance costs, and future environmental compliance costs could have a material adverse effect on our cash flows and/or results of operations.
Our businesses are subject to extensive federal, state, local and foreign statutes, rules and regulations relating to environmental protection, including air quality, water quality and usage, wastewater discharge, solid waste management, hazardous waste disposal and remediation, conservation of natural resources, wetlands and wildlife, renewable energy resources, climate change and GHG emissions. We are required to obtain numerous governmental permits, licenses, certificates and other approvals to construct and operate our businesses. Additionally, to comply with these legal requirements, we must spend significant amounts on environmental monitoring, pollution control equipment, mitigation costs and emissions fees. Our regulated utilities may be materially adversely affected if these additional costs for projects are not recoverable in rates. In addition, we may be ultimately responsible for all on-site liabilities associated with the environmental condition of our projects and properties; in each case regardless of when the liabilities arose and whether they are known or unknown, which exposes us to risks arising from
contamination at our former or existing facilities or with respect to offsite waste disposal sites that have been used in our operations. In the case of our California and other regulated utilities, some of these costs may not be recoverable in rates. Our facilities, including those in our JVs, are subject to laws and regulations that have been the subject of increased enforcement activity with respect to power generation facilities. Failure to comply with applicable environmental laws, regulations and permits may subject our businesses to substantial penalties and fines and/or significant curtailments of our operations, which could materially adversely affect our cash flows and/or results of operations.
Increasing international, national, regional and state-level environmental concerns as well as related new or proposed legislation and regulation may have substantial negative effects on our operations, operating costs and the scope and economics of proposed expansions, which could have a material adverse effect on our results of operations, cash flows and/or prospects. In particular, state-level laws and regulations, as well as potential state, national and international legislation and regulation relating to the control and reduction of GHG emissions, may materially limit or otherwise materially adversely affect our operations. For example, SB 100 requires each California utility, including SDG&E, to procure 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 the State of California’s retail electricity supply with a mix of RPS-eligible and zero-carbon resources by 2045, for a total of 100% clean energy. 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 into all relevant planning. Our California Utilities may be materially adversely affected if these additional costs are not recoverable in rates. Even if recoverable, the effects of existing and proposed GHG emission reduction standards may cause rates to increase to levels that substantially reduce customer demand and growth and may have a material adverse effect on the California Utilities’ cash flows. SDG&E may also be subject to significant penalties and fines if certain mandated renewable energy goals are not met.
In addition, existing and future laws, orders and regulations regarding mercury, nitrogen and sulfur oxides, particulates, methane or other emissions could result in requirements for additional monitoring, pollution monitoring and control equipment, safety practices or emission fees, taxes or penalties that could materially adversely affect our results of operations and/or cash flows. Moreover, existing rules and regulations may be interpreted or revised in ways that may materially adversely affect our results of operations and/or cash flows.
Our businesses, results of operations, financial condition and/or cash flows may be materially adversely affected by the outcome of litigation against us.
Sempra Energy and its subsidiaries are defendants in numerous lawsuits and arbitration proceedings, including in connection with the Aliso Canyon natural gas storage facility natural gas leak. We have spent, and continue to spend, substantial amounts of money and time defending these lawsuits and proceedings, and in related investigations and regulatory proceedings. We discuss pending proceedings in Note 16 of the Notes to Consolidated Financial Statements. The uncertainties inherent in lawsuits, arbitrations and other legal proceedings make it difficult to estimate with any degree of certainty the 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 our customers, which in each case could materially adversely affect our businesses, results of operations, financial condition and/or cash flows.
We cannot and do not attempt to fully hedge our assets or contract positions against changes in commodity prices. In addition, for those contract positions that are hedged, our hedging procedures may not mitigate our risk as planned.
To reduce financial exposure related to commodity price fluctuations, we may enter into contracts 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. As part of this strategy, we may use forward contracts, physical purchase and sales contracts, futures, financial swaps, and options. 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 planned, fluctuating commodity prices could have a material adverse effect on our results of operations, cash flows and/or financial condition. Certain of the contracts we may use for hedging purposes are subject to fair value accounting. Such accounting may result in gains or losses in earnings for those contracts. In certain cases, these gains or losses may not reflect the associated losses or gains of the underlying position being hedged.
Risk management procedures may not prevent or mitigate losses.
Although we have in place risk management and control systems that use advanced methodologies to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended by our businesses or may not work as planned. In addition, daily value-at-risk and loss limits are based on historic price movements. If prices significantly or persistently deviate from historic prices, the limits may not protect us from significant losses. As a result of
these and other factors, there is no assurance that our risk management procedures will prevent or mitigate losses that would materially adversely affect our results of operations, cash flows and/or financial condition.
The operation of our facilities depends on good labor relations with our employees.
Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. Our collective bargaining agreements are generally negotiated on a company-by-company basis. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows.
In addition to general information and cyber risks that all large corporations face (e.g. malware, malicious intent by insiders and inadvertent disclosure of sensitive information), we face evolving cybersecurity risks associated with protecting sensitive and confidential customer information, smart grid infrastructure, and natural gas pipeline and storage infrastructure.
Existing business technologies and the deployment of new business technologies represent a large-scale opportunity for attacks on our information systems and confidential customer information, as well as on the integrity of the energy grid and the natural gas infrastructure. Additionally, we often rely on third party vendors to deploy new business technologies and maintain, modify and update our systems, including systems that manage sensitive information. These third parties could fail to establish adequate risk management and information security measures to protect our systems and information. While our computer systems have been, and will continue to be, subjected to computer viruses or other malware, unauthorized access attempts, and cyber- or phishing-attacks, to date we have not detected a material breach of cybersecurity. Addressing these risks is the subject of significant ongoing activities across Sempra Energy’s businesses, including investing in risk management and information security measures to protect our systems. The cost and operational consequences of implementing, maintaining and enhancing further system protection measures could increase significantly to overcome increasingly intense, complex and sophisticated cyber risks. Despite our best efforts, our businesses may not be fully insulated from cyber-attacks and system disruptions. An attack on our information systems, the integrity of the energy grid, our pipelines and distribution and storage infrastructure or one of our facilities, or unauthorized access to confidential customer information, could result in energy delivery service failures, financial and reputational loss, violations of privacy laws, customer dissatisfaction and litigation, any of which, in turn, could have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.
In the ordinary course of business, Sempra Energy and its subsidiaries collect and retain sensitive information, including personal identification information about customers and employees, customer energy usage and other information. The theft, damage or improper disclosure of sensitive electronic data can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation. Sempra Energy maintains cyber liability insurance, but 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 the consequences of personal, confidential or proprietary information being compromised and there is no guarantee that the insurance that we do maintain will continue to be available at rates that we believe are commercially reasonable.
Further, as seen with recent cyber-attacks around the world, the goal of a cyber-attack may be primarily to inflict large-scale harm on a company and the places where it operates. Any such cyber-attack could cause widespread disruptions to our operating, financial and administrative systems, including the destruction of critical information and programming that could materially adversely affect our business operations and the integrity of the power grid, negatively impact our ability to produce accurate and timely financial statements or comply with ongoing disclosure obligations or other regulatory requirements, and/or release confidential information about our company and our customers, employees and other constituents, any of which could lead to sanctions or negatively affect the general perception of our business in the financial markets and which could have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.
Risks Related to the California Utilities
The California Utilities are subject to extensive regulation by state, federal and local legislative and regulatory authorities, which may materially adversely affect us.
The CPUC regulates the California Utilities’ rates, except SDG&E’s electric transmission rates which are regulated by the FERC. The CPUC also regulates, among other matters, the California Utilities’:
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conditions of service
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sales of securities
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rates of return
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capital structure
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rates of depreciation
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long-term resource procurement
The CPUC conducts various reviews and audits of utility operations, safety standards and practices, compliance with CPUC regulations and standards, affiliate relationships and other matters. These reviews and audits may result in disallowances, fines and penalties that could materially adversely affect our financial condition, results of operations and/or cash flows. SoCalGas and SDG&E may be subject to penalties or fines related to their operation of natural gas pipelines and storage and, for SDG&E, electric operations, under regulations concerning natural gas pipeline safety and citation programs concerning both gas and electric safety, which could have a material adverse effect on their results of operations, financial condition and/or cash flows. We discuss various CPUC proceedings relating to the California Utilities’ rates, costs, incentive mechanisms and performance-based regulation in Notes 4, 15 and 16 of the Notes to Consolidated Financial Statements.
The CPUC periodically approves the California Utilities’ rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments, as well as settlements, while incorporating a risk-based decision-making framework. Delays by the CPUC on decisions authorizing recovery or denying recovery, after-the-fact reasonableness reviews with unclear standards, authorizations for less than full recovery or rejection of their settlements may adversely affect the working capital, cash flows and financial condition of each of the California Utilities. If the California Utilities receive an adverse CPUC decision and/or actual capital expenditures and/or operating costs were to exceed the amounts approved by the CPUC, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
SoCalGas and SDG&E have significantly invested and continue to invest in major programs, such as PSEP, under an approved CPUC framework. However, the total investment to date is substantially subject to CPUC reasonableness review. Although we believe these costs have been prudently incurred, the standards applied by the CPUC could result in the disallowance of a portion of these incurred costs, which could materially and adversely affect SDG&E’s, SoCalGas’ and Sempra Energy’s results of operations, financial condition and cash flows.
In California, there are laws that establish rules governing, among other subjects, communications between CPUC officials, CPUC staff and regulated utilities. Rules and processes around ex parte communications could result in delayed decisions, increased investigations, enforcement actions and penalties. In addition, the CPUC or other parties may initiate investigations of past communications between public utilities and CPUC officials and staff that could result in reopening completed proceedings for reconsideration.
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.
The California Utilities may be materially adversely affected by new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies. In addition, existing legislation or regulations may be revised or reinterpreted. New, revised or reinterpreted legislation, regulations, decisions, orders or interpretations could change how the California Utilities operate, could affect their ability to recover various costs through rates or adjustment mechanisms, or could require them to incur substantial additional expenses.
Our California Utilities are also affected by the activities of organizations such as TURN, Utility Consumers’ Action Network, Sierra Club and other stakeholder, advocacy and activist groups. To the extent that these groups are successful in influencing our California Utilities’ operations, this could have a material adverse effect on the California Utilities’ businesses, cash flows, results of operations, financial condition and/or prospects.
The Wildfire Legislation may not adequately protect SDG&E from liability from catastrophic wildfires in its service territory and we may be unable to obtain sufficient insurance coverage at a reasonable cost or at all.
In July 2019, the Governor of California signed the Wildfire Legislation into law, which addresses certain important 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 did not change the doctrine of inverse condemnation, which imposes strict liability on a utility (meaning that the utility may be found liable regardless of fault) whose equipment is determined to be a cause of a fire. Rather, the Wildfire Legislation established a revised legal standard for the recovery of wildfire costs (Revised Prudent Manager Standard) and established the Wildfire Fund designed to provide liquidity to participating California electric IOUs 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. We are unable to predict whether the Wildfire Legislation will be effectively implemented and its impact on SDG&E’s ability to recover certain costs and expenses in cases where SDG&E’s equipment is determined to be a cause of a fire, and specifically in the context of the application of inverse condemnation.
We have experienced increased costs and difficulties in obtaining insurance coverage for wildfires that could arise from the California Utilities’ operations, particularly SDG&E’s operations. In addition, the insurance that has been obtained for wildfire liabilities may not be sufficient to cover all losses that we may incur, or may not be available in sufficient amounts to meet the primary insurance required by the Wildfire Legislation of $1 billion. Uninsured losses may not be recoverable in customer rates. Increases in the cost of insurance may be challenged when we seek cost recovery. California courts have invoked the doctrine of inverse condemnation for wildfire damages, whereby if a utility company’s equipment, such as its electric distribution and transmission lines, are determined to be a cause of one or more fires, the utility could be held strictly liable for damages, as well as attorneys’ fees, without having been found negligent. As a result of the strict liability standard applied to wildfires, recent losses recorded by insurance companies, and the risk of an increase in the number and size of wildfires, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, even if insurance for wildfire liabilities is available, it may not be available in such amounts as are necessary to cover potential losses. A loss which is neither fully insured nor can be recovered in customer rates, such as the CPUC decision denying SDG&E’s recovery of costs for the 2007 wildfires, could materially adversely affect Sempra Energy’s and one or both of the California Utilities’ financial condition, cash flows and results of operations. We are unable to predict whether we would be allowed to recover in rates or from the Wildfire Fund the costs of any uninsured losses.
We monitor weather conditions continuously to help ensure the safe operation of our facilities during the periods of elevated wildfire ignition risk. Should conditions become extreme, we may de-energize certain of our facilities as a last resort to minimize this safety risk to the public. Such “public safety power shutoffs” could be subject to increased scrutiny by regulators and law makers, and may lead to increased risk of penalties and liability for damages. There can be no assurance that such costs would be recoverable in rates.
Extreme weather conditions, changing weather patterns and population growth in areas of the State of California in environments with historically higher risk of wildfires could materially affect the California Utilities’ and Sempra Energy’s business, financial condition, results of operations, liquidity, and cash flows.
Frequent and more severe drought conditions, unseasonably warm temperatures, very low humidity and stronger winds have increased the degree and prevalence of wildfires in California including in SDG&E’s and SoCalGas’ service territories, which could place third party property and our electric and natural gas infrastructure in jeopardy and reduce the availability of hydroelectric generators. This could result in temporary power shortages in SDG&E’s and SoCalGas’ service territories and/or catastrophic destruction of third-party property for which SDG&E or SoCalGas may be liable and unable to recover from ratepayers or may have inadequate insurance coverage. The Wildfire Legislation, signed into law in July 2019, includes a number of measures primarily intended to address certain important issues related to catastrophic wildfires in the State of California, including wildfire mitigation, cost recovery standards and requirements, a wildfire fund, a cap on liability, and the establishment of a wildfire safety board. However, in the event of a significant wildfire involving SDG&E equipment, the standards prescribed by the Wildfire Legislation may not be applied by the State of California consistently or the Wildfire Fund could be completely exhausted due to fires in other California IOUs’ service territories, by fires in SDG&E’s service territory or by a combination thereof, which could impact our ability to timely access capital necessary to address, in whole or in part, inverse condemnation and other liabilities. In addition, the State of California has been subject to housing shortages such that certain local land use policies and forestry management practices have been relaxed in certain cases to allow for the construction and development of residential and commercial projects in high risk fire areas that may not have the infrastructure or contingency plans necessary to address such risk.
Severe rainstorms and associated high winds in our service territories, as well as flooding and mudslides where vegetation has been destroyed as result of human modification or wildfires, could damage our electric and natural gas infrastructure, resulting in increased expenses, including higher maintenance and repair costs and interruptions in natural gas and electricity delivery services. As a result, these events can have significant financial consequences, including regulatory penalties and disallowances if the California Utilities encounter difficulties in restoring service to their customers on a timely basis. Further, the cost of storm restoration efforts may not be fully recoverable through the regulatory process. Any such events could have a material adverse effect on our businesses, financial condition, results of operations and cash flows.
Events or conditions caused by climate change, including risk of wildfires, severe weather conditions and flooding caused by rising sea levels, could have a greater impact on the California Utilities’ operations than the California Utilities currently
anticipate. If the CPUC fails to adjust the California Utilities’ rates to reflect the impact of events or conditions caused by climate change or if a major fire is determined to be caused by our equipment, Sempra Energy’s and the California Utilities’ business, financial condition, results of operations, liquidity, and cash flows could be materially affected.
The California Utilities are subject to risks arising from the operation, maintenance and upgrades of their natural gas and electricity infrastructure and information technology systems, which, if they materialize, could adversely affect Sempra Energy’s and the California Utilities’ financial results.
The California Utilities own and operate electric transmission and distribution facilities and natural gas transmission, distribution and storage facilities, which are, in many cases, interconnected and/or managed by information technology systems. The California Utilities undertake substantial capital investment projects to construct, replace, improve and upgrade these facilities and systems, but while these capital investment projects are in process and even once completed, there is a risk of, among other things, potential breakdown or failure of equipment or processes due to aging infrastructure and information technology systems, human error in operations or maintenance, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental requirements and governmental interventions, and performance below expected levels. In addition, as discussed above, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could also be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
Additional risks associated with the ability of the California Utilities to safely and reliably operate, maintain, improve and upgrade their facilities and systems, many of which are beyond the California Utilities’ control, include:
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challenges associated with meeting customer demand for natural gas and/or electricity that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;
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a prolonged widespread electrical black-out that results in damage to the California Utilities’ equipment or damage to property owned by customers or other third parties;
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inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that could lead to public or employee harm or extended outages; severe weather events such as storms, tornadoes, floods, drought, earthquakes, tsunamis, fires, pandemics, solar events, electromagnetic events or other natural disasters;
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the release of hazardous or toxic substances into the air, water or soil, including gas leaks from natural gas pipelines or storage facilities; and
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attacks by third parties, including cyber-attacks, acts of terrorism, vandalism or war.
The occurrence of any of these events could affect demand for natural gas or electricity; cause unplanned outages; damage the California Utilities’ assets and/or operations; damage the assets and/or operations of third parties on which the California Utilities rely; damage property owned by customers or others; and cause personal injury or death. As a result, the California Utilities could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties. Any such events could materially adversely affect Sempra Energy’s and one or both of the California Utilities’ financial condition, cash flows and results of operations.
SoCalGas has incurred and may continue to incur significant costs, expenses and other liabilities related to the natural gas leak at its Aliso Canyon natural gas storage facility and mitigating local community environmental impacts from the Leak, some or a substantial portion of which may not be recoverable through insurance, and SoCalGas also may incur significant liabilities for damages, restitution, fines, penalties and other costs, and emissions mitigation activities as a result of this incident, some or a significant portion of which may not be recoverable through insurance or may exceed insurance coverage.
In October 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility in Los Angeles County. As described in “Civil and Criminal Litigation” and “Regulatory Proceedings” 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 and Criminal Litigation
As of February 21, 2020, 393 lawsuits, including approximately 36,000 plaintiffs, are pending against SoCalGas related to the Leak, some of which have also named Sempra Energy. All these cases, other than a matter brought by the Los Angeles County District Attorney and the federal securities class action, are coordinated before a single court in the LA Superior Court for pretrial management. The court has scheduled an initial trial for June 24, 2020 for a small number of randomly selected individual plaintiffs. For a more detailed description of the civil and criminal lawsuits brought against us, see Note 16 of the Notes to Consolidated Financial Statements.
Five shareholder derivative actions alleging breach of fiduciary duties have been filed against certain officers and directors of Sempra Energy and/or SoCalGas, four of which were joined in a Consolidated Shareholder Derivative Complaint in August 2017. These complaints were dismissed, and shareholders filed an amended complaint in February 2020. A federal securities class action alleging violation of the federal securities laws also was filed against Sempra Energy and certain of its officers which is on appeal following dismissal by the court.
A misdemeanor criminal complaint was filed by the LA County District Attorney’s office, as to which SoCalGas entered a settlement that was approved by the LA Superior Court but is subject to appeal by certain residents. Additional litigation, including by public entities, and criminal complaints may be filed against us in the future related to the Leak or our responses thereto.
The costs of defending against or resolving the civil and criminal lawsuits, and any compensatory, statutory or punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, if awarded or imposed, as well as the costs of mitigating the actual natural gas released, could be significant. If any of these costs are not covered by insurance (including any costs in excess of applicable policy limits), if there are significant 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 could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Governmental Investigations, Orders and Additional Regulation
In January 2016, CalGEM and the CPUC selected Blade to conduct, under their supervision, an independent analysis of the technical root cause of the Leak, to be funded by SoCalGas. The root cause analysis was released in May 2019 and concluded that SoCalGas had complied with gas storage regulations in existence at the time of the Leak and that the related compliance activities conducted prior to the Leak did not find indications of a casing integrity issue, but that there were also measures, though not required by the gas storage regulations at the time, that could have been taken to aid in the early identification of corrosion and that, in the opinion of Blade, would have prevented or mitigated the Leak. In addition, CalGEM is investigating the Leak.
In June 2019, the CPUC opened an OII to consider penalties against SoCalGas for the Leak. The first phase will consider whether SoCalGas violated 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 Safety Enforcement Division (SED) and Blade during the pre-formal investigation, and whether any of the mitigation proposed by Blade should be implemented to the extent not already done. In November 2019, SED, based largely on the Blade report, alleged a total of 330 violations, asserting that SoCalGas violated California Public Utilities Code Section 451 and failed to cooperate in the investigation and to keep proper records. Hearings in the first phase of the OII are scheduled to begin in April 2020. The second phase will consider whether SoCalGas should be sanctioned for the Leak and what penalties, if any, should be imposed for any violations proven in the first phase, as well as 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.
Higher operating costs and additional capital expenditures incurred by SoCalGas as a result of new laws, orders, rules and regulations arising out of this incident or our responses thereto could be significant and may not be recoverable through insurance or in customer rates. In addition, any of these investigations could result in findings of violations of laws, orders, rules or regulations as well as fines, sanctions and other penalties. SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations may be materially adversely affected by any such new laws, orders, rules and regulations or by these investigations.
Natural Gas Storage Operations and Reliability
Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and heating needs in the winter. The Aliso Canyon natural gas storage facility, with a storage capacity of 86 Bcf (representing 63% of SoCalGas’ natural gas storage capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system. As a result of the Leak, SoCalGas suspended injection of natural gas into the Aliso Canyon natural gas storage facility beginning in October 2015 and, following a comprehensive safety review and authorization by CalGEM and the CPUC’s Executive Director, resumed limited injection operations in July 2017. In February 2017, the CPUC opened a proceeding pursuant to SB 380 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.
If the Aliso Canyon natural gas storage facility were to be permanently closed, or if future cash flows were otherwise insufficient to recover its carrying value, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31,
2019, the Aliso Canyon natural gas storage facility had a net book value of $769 million. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, and SoCalGas’ and Sempra Energy’s results of operations, cash flows and financial condition may be materially adversely affected.
Insurance and Estimated Costs
Excluding directors’ and officers’ liability insurance, we have at least four kinds of insurance policies that together we estimate provide between $1.2 billion to $1.4 billion in insurance coverage, depending on the nature of the claims. At December 31, 2019, SoCalGas’ estimate of costs related to the Leak of $1,116 million includes $1,086 million of costs recovered or probable of recovery from insurance. This estimate may rise significantly as more information becomes available. Costs not included in the $1,116 million cost estimate could be material. We have received insurance payments for many of our costs, including temporary relocation and associated processing costs, control-of-well expenses, costs of the government-ordered response to the Leak, legal costs and lost gas.
If any costs are not covered by insurance (including any costs in excess of applicable policy limits), if there are significant 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 could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
As described in “Civil and Criminal Litigation” above, the actions against us seek compensatory, statutory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs, which except for the amounts paid or estimated to settle certain actions, are not included in the $1,116 million cost estimate as it is not possible at this time to predict the outcome of these actions or reasonably estimate the amount of damages, restitution or civil, administrative or criminal fines, sanctions, penalties or other costs. This cost estimate also does not include future legal costs to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate. Furthermore, the cost estimate does not include certain other costs incurred by Sempra Energy through December 31, 2019 associated with defending shareholder derivative lawsuits. Costs not included in the $1,116 million cost estimate could be material. There can be no assurance that we will be successful in obtaining insurance coverage for these costs under the applicable policies, and to the extent we are not successful in obtaining coverage or these costs exceed the amount of our coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Additional Information
We discuss Aliso Canyon natural gas storage facility matters further in Note 16 of the Notes to Consolidated Financial Statements.
Natural gas pipeline safety assessments may not be fully or adequately recovered in rates.
The California Utilities test or replace natural gas transmission pipelines located in populated areas that either have not been pressure tested or lack sufficient documentation of a pressure test, to enhance existing valve infrastructure and to retrofit pipelines to allow for the use of in-line inspection technology, referred to as SoCalGas’ and SDG&E’s PSEP.
The CPUC established criteria to determine the amounts related to PSEP that may be recovered from ratepayers and the processes for recovery of such amounts, including providing that such costs are subject to a reasonableness review. In the future, certain PSEP costs may be subject to recovery as determined by separate regulatory filings with the CPUC, including GRC filings. PSEP-related proceedings before the CPUC regarding the California Utilities’ reasonableness review and cost recovery requests are often challenged by intervening parties. In the future, consumer advocacy groups may similarly challenge the California Utilities’ petitions for recovery and recommend disallowances in whole or in part with respect to applications to recover PSEP costs, including through GRC filings.
From 2011 through 2019, SoCalGas and SDG&E have invested and have or plan to seek recovery for approximately $1.8 billion and $445 million, respectively, in PSEP, with substantial additional expenditures planned. As of December 31, 2019, SoCalGas and SDG&E have received approval for recovery of $1.3 billion and $15 million, respectively. On January 30, 2020 SoCalGas and SDG&E reached a settlement with certain intervenors in the 2018 reasonableness review proceeding, which would resolve all but one issue regarding the period of recovery. The settlement is subject to CPUC approval. Beginning in 2019, the majority of investments in PSEP projects are being recovered in base rates as approved in the 2019 GRC FD. If the CPUC denies or significantly delays rate recovery for PSEP and other gas pipeline safety costs incurred by SoCalGas and SDG&E, it could materially adversely affect the respective company’s cash flows, financial condition, results of operations and prospects.
The California Utilities are subject to increasingly stringent safety standards and the potential for significant penalties if regulators deem either SDG&E or SoCalGas to be out of compliance.
SB 291 requires the CPUC to develop and maintain a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, and delegates citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. Under the enforcement program, the maximum penalty is $50,000 per offense. Each day of an ongoing violation may be counted as an additional offense. CPUC staff has authority to issue citations up to an administrative limit of $8 million per citation under either program and such citations may be appealed to the CPUC. Although citations issued under these enforcement programs do include an administrative limit, penalties issued by the CPUC can exceed this limit, having exceeded $1.5 billion in one instance for an unrelated third party.
If the CPUC or its staff determine that either of SDG&E’s or SoCalGas’ operations and practices are not in compliance with applicable safety standards and operating procedures, the corrective or mitigation actions required to become in conformance, if not sufficiently funded in customer rates, and any penalties imposed, could materially adversely affect that company’s cash flows, financial condition, results of operations and prospects.
The failure by the CPUC to continue reforms of SDG&E’s rate structure, including the implementation of charges independent of consumption volume and reforms to reduce NEM rate subsidies, could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects.
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.
The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation (primarily solar installations). Under NEM, qualifying customer-generators receive a full retail rate for the energy they generate that is fed to the utility’s power grid. This occurs during times when the customer’s generation exceeds their own energy usage (wholesale rates apply only if a customer’s annual generation exceeds their annual consumption). Under this structure, NEM customers do not pay their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain limitations, while they still receive electricity from the system when their self-generation is inadequate to meet their electricity needs. The unpaid NEM costs are subsidized by customers not participating in NEM. Accordingly, as higher electric-use residential customers switch to NEM and self-generate energy, the burden on the remaining customers increases, which in turn encourages more self-generation, further increasing rate pressure on existing customers.
In July 2015, the CPUC adopted a decision that provided a framework for rates that we believe are more transparent, fair and sustainable. The framework provides for a minimum monthly bill, fewer rate tiers and a gradual reduction in the differences between the tiered rates, and directs the utilities to pursue expanded time-of-use rates. The framework will be fully implemented in 2020 and should result in relief for higher-use customers and a rate structure that better aligns rates with actual costs to serve customers. The decision also establishes a process for utilities to seek implementation of a fixed charge for residential customers in 2020, subject to certain conditions. We believe the establishment of a charge independent of consumption volume for residential customers may become more critical to help ensure rates are fair for all customers, including the NEM issue discussed above. Distributed energy resources and energy efficiency initiatives could generally reduce delivered volumes, increasing the importance of a fixed charge. In addition, the continuing increase of solar installations and other forms of self-generation adversely impacts the reliability of the electric transmission and distribution system and could increase fixed costs.
If the CPUC fails to continue to reform SDG&E’s rate structure to maintain 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 lead to the disallowance of recovery for our costs, including power procurement costs, operating or capital costs, or the imposition of fines and penalties. Any of these developments could have a material adverse effect on SDG&E’s and Sempra Energy’s business, cash flows, financial condition, results of operations 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, such as solar, energy storage, energy efficiency and demand response technologies. This growth will eventually 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 distributed energy resources. The CPUC is conducting proceedings to: evaluate various demonstration projects and pilots; implement changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources; consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by distributed energy resources; and if feasible, what, if any, compensation would be appropriate; and clarify the role of the electric distribution grid operator. These proceedings may result in new regulations, policies and/or
operational changes that could materially adversely affect SDG&E’s and Sempra Energy’s businesses, cash flows, financial condition, results of operations 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, customers do have the ability to receive procurement service from a load serving entity other than SDG&E, through programs such as DA and CCA. DA is currently limited by a cap based on gigawatt hours. Utility customers could also receive procurement through CCA, if the customer’s local jurisdiction (city) offers such a program. Several local political jurisdictions, including the City and County of San Diego and other municipalities, are considering implementing or are implementing a CCA, which could result in SDG&E providing procurement service for less than half of its current customer load as early as 2021. When customers are served by another load serving entity, SDG&E no longer procures electricity for this departing load and the associated costs of the utility’s procured resources could then be borne by SDG&E’s remaining bundled procurement customers. State law requires that customers opting to have a CCA procure their electricity must absorb the cost of above-market electricity procurement commitments already made by SDG&E on their behalf. If adequate mechanisms are not implemented to ensure compliance with state law, remaining bundled customers of SDG&E could potentially experience large increases in rates for commodity costs under commitments made on behalf of CCA customers prior to their departure, which may not be fully recoverable in rates by SDG&E. If legislative, regulatory or legal action were taken to prevent the timely recovery of these procurement costs or if mechanisms are not in place to ensure compliance with state law, the unrecovered costs could have a material adverse effect on SDG&E’s and Sempra Energy’s cash flows, financial condition and results of operations.
Natural gas and natural gas storage has increasingly been the subject of political and public scrutiny, including a desire by some to further limit or eliminate reliance on natural gas as an energy source.
California legislators and stakeholder, advocacy and activist groups have expressed a desire to further limit or eliminate reliance on natural gas as an energy source by advocating increased use of renewable energy and electrification in lieu of the use of natural gas. The CPUC initiated an OIR to update gas reliability standards, determine the regulatory changes necessary to improve coordination between natural gas utilities and natural gas-fired electric generators, and implement a long-term planning strategy to manage the state’s transition away from natural gas-fueled technologies to meet California’s decarbonization goals. The OIR will be conducted in three phases. The first phase will address reliability standards. The second phase will address coordination between natural gas utilities and natural gas-fired electric generators. The third phase will implement a long-term planning strategy. Comments on the scope of the new OIR were due on February 26, 2020. A substantial reduction or the elimination of natural gas as an energy source in California could have a material adverse effect on SDG&E’s, SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
SDG&E may incur substantial costs and liabilities as a result of its partial ownership of a nuclear facility that is being decommissioned.
SDG&E has a 20% ownership interest in SONGS, formerly a 2,150-MW nuclear generating facility near San Clemente, California, that is in the process of being decommissioned by Edison, the majority owner of SONGS. SDG&E, and each of the other owners, is responsible for financing its share of expenses and capital expenditures, including decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to the risks of owning a partial interest in a nuclear generation facility, which include:
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the potential release of a radioactive material including from a natural disaster such as an earthquake or tsunami that could cause catastrophic harm to human health and the environment;
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the potential harmful effects on the environment and human health resulting from the prior operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
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limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with operations and the decommissioning of the facility; and
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uncertainties with respect to the technological and financial aspects of decommissioning the facility.
In addition, SDG&E maintains NDTs for providing funds to decommission SONGS. Trust assets have been generally invested in equity and debt securities, which are subject to significant market fluctuations. A decline in the market value of trust assets or an adverse change in the law regarding funding requirements for decommissioning trusts could increase the funding requirements for these trusts, which in each case may not be fully recoverable in rates. Furthermore, CPUC approval is required in order to make withdrawals from these trusts. CPUC approval for certain expenditures may be denied by the CPUC altogether if the CPUC determines that the expenditures are unreasonable. Finally, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the trust funds. Rate recovery for overruns would require CPUC approval, which may not occur.
Interpretations of tax regulations could impact access to NDT funds for reimbursement of spent nuclear fuel management costs. In December 2016, the IRS and the U.S. Department of Treasury issued proposed regulations that clarify the definition of “nuclear decommissioning costs.” These proposed regulations will be effective prospectively once they are finalized. SDG&E is awaiting the adoption of, or additional refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to timely access the NDT funds for reimbursement or payment of the spent fuel management costs incurred in 2017 and subsequent years. Until the litigation against the DOE by Edison and SDG&E seeking recovery of spent fuel management costs is resolved or IRS regulations regarding spent fuel management costs are confirmed to apply, SDG&E expects to continue to pay for its share of such spent fuel management costs without reimbursement from the NDT. If SDG&E is unable to obtain timely access to the trusts for these costs, SDG&E’s cash flows could be negatively impacted.
The occurrence of any of these events could result in a substantial reduction in our expected recovery and have a material adverse effect on SDG&E’s and Sempra Energy’s businesses, cash flows, financial condition, results of operations and/or prospects.
Risks Related to Our Interest in Oncor
Certain ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management and policies of Oncor.
Various “ring-fencing” measures are in place to enhance Oncor’s separateness from its owners and to mitigate the risk that Oncor would be negatively impacted in the event of a bankruptcy or other adverse financial developments affecting its owners. This ring-fence creates both legal and financial separation between Oncor Holdings, Oncor and their subsidiaries, on the one hand, and Sempra Energy and its affiliates and subsidiaries, on the other hand.
In accordance with the ring-fencing measures, governance mechanisms and commitments we made in connection with the Merger, we and Oncor are subject to various restrictions, including, among others:
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seven members of Oncor’s 13-person board of directors will be independent directors in relation to Sempra Energy and any other direct or indirect owners of Oncor. With respect to the non-independent directors, two will be designated by Sempra Energy, two will be appointed by Oncor’s minority owner, TTI, and two will be current or former Oncor officers;
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Oncor may not pay any dividends 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;
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Oncor will not pay dividends if that payment would cause its debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT;
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if Oncor’s senior secured debt by any of the three major 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;
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there must be maintained certain “separateness measures” that reinforce the financial separation of Oncor from Sempra Energy, including a requirement that dealings between Oncor and Sempra Energy 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;
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a majority of Oncor’s independent directors 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 of such expenditures in the budget for the preceding fiscal year or multi-year period, as applicable; and
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Sempra Energy will continue to hold indirectly at least 51% of the ownership interests in Oncor Holdings and Oncor for at least five years following the closing of the Merger, unless otherwise specifically authorized by the PUCT.
As a result, 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 issues and actions. We have limited representation on the Oncor Holdings and Oncor board of directors, which are controlled by independent directors. The Oncor directors have considerable autonomy and, as described in our commitments, have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may be contrary to our best interests or be in opposition to our preferred strategic direction for Oncor. To the extent that they take actions that are not in our interests, the financial condition, results of operations and/or prospects of Sempra Energy may be materially adversely affected.
If Oncor fails to respond to challenges in the electric utility industry, including changes in regulation, its results of operations and financial condition could be adversely affected, and this could materially adversely affect us.
Because Oncor is regulated by both U.S. federal and Texas state authorities, it has been and will continue to be affected by legislative and regulatory developments. The costs and burdens associated with complying with these regulatory requirements and adjusting Oncor’s business to legislative and regulatory developments may have a material adverse effect on Oncor. Moreover,
potential legislative changes, regulatory changes or other market or industry changes may create greater risks to the predictability of utility earnings generally. If Oncor does not successfully respond to these changes, it could suffer a deterioration in its results of operations, financial condition and/or prospects, which could materially adversely affect our results of operations, financial condition and/or prospects.
Oncor’s operations are capital intensive and it could have liquidity needs that may require us to make additional investments in Oncor.
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 a substantial portion of its cash needs with the proceeds from indebtedness. In the event that Oncor fails to meet its capital requirements, we may elect to make additional investments in Oncor. Similarly, if Oncor is unable to access sufficient capital to finance its ongoing needs, we may elect to make additional investments in Oncor which could be substantial and which would reduce the cash available to us for other purposes, could increase our indebtedness and could ultimately materially adversely affect our results of operations, financial condition and/or prospects. In that regard, our commitments to the PUCT prohibit us from making loans to Oncor. As a result, if Oncor requires additional financing and cannot obtain it from other sources, we may elect to make a capital contribution, rather than a loan, to Oncor.
Sempra Energy 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 spinoff), 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 stockholders 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 of the spin-off, 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, EFH sought and received a supplemental private letter ruling from the IRS and Sempra Energy and EFH received tax opinions from their respective counsel 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 Energy and EFH, now Sempra Texas Holdings Corp. and a subsidiary of Sempra Energy. 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 as a result, could be successfully challenged by the IRS. If it is determined that the Merger causes the spin-off not to qualify for the Intended Tax Treatment, Sempra Energy, 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 the results of operations, financial condition and/or prospects of Sempra Energy and on the market value of our common stock, preferred stock and debt securities. Should the IRS invalidate the private letter ruling and/or the supplemental private letter ruling, Sempra Texas Holdings Corp. has administrative appeal rights including the right to challenge any adverse IRS position in court.
Risks Related to our Businesses Other Than the California Utilities and Our Interest in Oncor
Business development activities may not be successful and projects under construction may not commence operation as scheduled, be completed within budget or operate at expected levels, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
The acquisition, development, construction and expansion of LNG liquefaction, marine and inland ethane and liquid fuels, and LPG terminals and storage; natural gas, propane and ethane pipelines and distribution and storage facilities; electric generation, transmission and distribution infrastructure; and other energy infrastructure projects involve numerous risks. We may be required to spend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal and other expenses before we can determine whether a project is feasible, economically attractive, or capable of being built.
Success in developing a project is contingent upon, among other things:
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negotiation of satisfactory EPC agreements
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negotiation of satisfactory LNG offtake and equity agreements
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negotiation of supply, natural gas and LNG sales agreements or firm capacity service agreements and PPAs
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timely receipt of required governmental permits, licenses and other authorizations and maintenance of these authorizations
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our counterparties’ financial or other ability to fulfill their contractual commitments
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timely implementation and satisfactory completion of construction
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obtaining adequate and reasonably priced financing for the project
Successful completion of a project may be materially adversely affected by, among other factors:
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unforeseen engineering problems
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construction delays due to adverse weather conditions, work stoppages, equipment unavailability and other events and contractor performance shortfalls
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our counterparties’ financial or other inability to fulfill their contractual commitments
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failure to obtain or maintain required governmental permits, licenses and other authorizations
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litigation
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unsettled property rights
If we are unable to complete a development project or if we have substantial delays or cost overruns, this could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
The operation of existing and future facilities also involves many risks, including the breakdown or failure of liquefaction, regasification and storage facilities, electric generation, transmission and distribution infrastructure or other equipment or processes, labor disputes, fuel interruption, environmental contamination and operating performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt liquefaction, generation, regasification, storage, transmission and distribution systems. The occurrence of any of these events could lead to our facilities being idled for an extended period of time or our facilities operating well below expected capacity levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Such occurrences could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.
The design, development and construction of the Cameron LNG liquefaction facility involves numerous risks and uncertainties.
We have a 50.2% interest in Cameron LNG JV, which is building an LNG export facility consisting of three liquefaction trains designed to a total nameplate capacity of 13.9 Mtpa of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day.
Cameron LNG JV has a lump-sum, turnkey EPC contract with a JV between CB&I, LLC (as assignee of CB&I Shaw Constructors, Inc.), a wholly owned subsidiary of McDermott International, Inc., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation. If the EPC contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, the project could face substantial construction delays and potentially significantly increased costs. In January 2020, McDermott International, Inc. filed for bankruptcy protection under Chapter 11 of the U.S. bankruptcy code. McDermott International, Inc. has stated that it expects all of its projects, including the three-train liquefaction project at Cameron LNG JV, to continue on an uninterrupted basis. However, we cannot be certain the Cameron LNG JV project will not be interrupted. If the contractor defaults under the EPC contract due to the bankruptcy of McDermott International, Inc. or for any other reason, such default could result in Cameron LNG JV’s engagement of a substitute contractor. The inability to complete the project in a timely manner or within our current expectations, cost overruns, and the other risks described above could have a material adverse effect on our business, results of operations, cash flows, financial condition, credit ratings and/or prospects.
If the estimated construction, financing and other project costs for the facility substantially exceed our contingency associated with the project budget adopted at the time of our final investment decision, we may have to make material additional, unexpected cash contributions. The majority of the investment in the liquefaction project is project-financed and the balance is provided by the project partners. Any failure by the project partners to make their required investments on a timely basis could result in project delays and could materially adversely affect the development of the project. In addition, Sempra Energy has guaranteed a maximum of up to $4.0 billion related to the project financing and financing-related agreements. These guarantees terminate upon Cameron LNG JV achieving “financial completion” of the initial three-train liquefaction project, including all three trains achieving commercial operation and meeting certain operational performance tests. Cameron LNG JV’s Loan Facility Agreements and related finance documents contain events of default customary for such financings, including a failure to achieve financial completion of the project by a financial completion deadline date of September 30, 2021 (with up to an additional 365 days extension beyond such date permitted in cases of force majeure). A delay in construction that results in a failure to achieve financial completion of the project by this financial completion deadline date would therefore result in an event of default under
Cameron LNG JV’s financing and a potential demand on Sempra Energy’s guarantees. We anticipate that the guarantees will be terminated approximately nine months after all three trains achieve commercial operation. If, due to Cameron LNG JV’s failure to satisfy the financial completion criteria, we are required to repay some or all of the $4.0 billion under our guarantees, any such repayments could have a material adverse effect on our business, results of operations, cash flows, financial condition and/or prospects.
We face many challenges to develop and complete our contemplated LNG export facilities.
In addition to the three-train Cameron LNG liquefaction facility described above, we are evaluating several other LNG export development opportunities. Sempra LNG is in discussions with the co-owners of Cameron LNG JV regarding the potential expansion of up to two additional liquefaction trains at the Cameron LNG liquefaction facility, is developing a proposed natural gas liquefaction project near Port Arthur, Texas, and, through a JV agreement with IEnova, is developing a proposed natural gas liquefaction project at IEnova’s existing ECA LNG Regasification facility in Baja California, Mexico to be developed in two phases (a mid-scale project referred to as ECA LNG JV Phase 1 and a large-scale project referred to as ECA LNG JV Phase 2). Each of these contemplated projects face numerous risks and must overcome significant hurdles before we can reach a final investment decision and proceed with construction. Further, a shift in the supply of natural gas could depress LNG prices and the cost advantages of exporting LNG from the U.S. In addition, global oil prices and their associated current and forward projections could reduce the demand for natural gas in some sectors and cause a corresponding reduction in projected global demand for LNG. This could result in increased competition among those developing projects in an environment of declining LNG demand, such as the Sempra Energy-sponsored export initiatives. Such reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, which could also lead to increased competition among the LNG suppliers for the declining LNG demand. At certain moderate levels, oil prices could also make LNG projects in other parts of the world more feasible and competitive with LNG projects from North America, thus increasing supply and the competition for the available LNG demand. A decline in natural gas prices outside the U.S. (which in many foreign countries are based on the price of crude oil) may also materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).
In connection with these LNG export development opportunities, which we discuss further in “Item 7. MD&A - Capital Resources and Liquidity - Sempra LNG,” we have entered into or may enter into Heads of Agreements, MOUs and/or similar agreements, all of which are or will be nonbinding and do not or will not obligate any of the parties to execute any agreements or participate in any such opportunities.
Any decisions by Sempra Energy or our potential counterparties to proceed with binding agreements with respect to the potential development (or expansion) of our liquefaction projects will require, among other things, obtaining customer commitments to purchase LNG, completion of project assessments and achieving other necessary internal and external approvals of each party. In addition, all our proposed projects are subject to a number of risks and uncertainties, including the receipt of a number of permits and approvals; finding suitable additional partners and customers; obtaining financing and incentives; negotiating and completing suitable commercial agreements, including equity acquisition and governance agreements, natural gas supply and transportation agreements, LNG sale and purchase agreements and construction contracts; and reaching a final investment decision.
Furthermore, there are a number of potential new projects under construction or in the process of development by various project developers in North America, in addition to ours, and given the projected global demand for LNG, the vast majority of these projects likely will not be completed. With respect to our Port Arthur, Texas project, this is a greenfield site, and therefore it may not have the advantages often associated with brownfield sites. The ECA LNG Regasification facility and ECA LNG JV proposed liquefaction project in Mexico are subject to on-going land and permit disputes that could make project financing, as well as finding suitable partners and customers, difficult. In addition, while we have completed the regulatory process for an LNG export facility in the U.S., the regulatory process in Mexico and the overlay of U.S. regulations for natural gas exports to an LNG export facility in Mexico are not well developed. There can be no assurance that a facility could be constructed without facing significant legal challenges and uncertainties, which in turn could make project financing, as well as finding suitable partners and customers for ECA LNG JV Phase 2, difficult. Finally, the ECA LNG Regasification facility currently has profitable long-term regasification contracts for 100% of the regasification facility’s capacity through 2028, making the decision to pursue ECA LNG JV Phase 2 dependent in part on whether the investment in a large-scale liquefaction project would, over the long term, be more beneficial than continuing to supply regasification services under our existing contracts.
There can be no assurance that our contemplated LNG export facilities will be completed, and our inability to complete one or more of our contemplated LNG export facilities could have a material adverse effect on our future cash flows, results of operations and prospects.
Domestic and international hydraulic fracturing operations are subject to political, economic and other uncertainties that could increase the costs of doing business, impose additional operating restrictions or delays, and adversely affect production of LNG and reduce or eliminate LNG export opportunities and demand.
Hydraulic fracturing operations in the U.S. and outside the U.S. face political and economic risks and other uncertainties with respect to their operations. Several states have adopted or are considering adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict the performance of or prohibit the 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 in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing). Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG exports and our ability to develop commercially viable LNG export facilities beyond the three-train Cameron LNG facility currently under construction.
Our businesses are exposed to market risks, including fluctuations in commodity prices, and our businesses, financial condition, results of operations, cash flows and/or prospects may be materially adversely affected by these risks.
We buy energy-related commodities from time to time for LNG facilities or power plants to satisfy contractual obligations with customers, in regional markets and other competitive markets in which we compete. Our revenues and results of operations could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities that we buy change in a direction or manner not anticipated and for which we had not provided adequately through purchase or sale commitments or other hedging transactions. Unanticipated changes in market prices for energy-related commodities can result from multiple factors, such as adverse weather conditions, commodity production levels, and energy and environmental regulations and legislation.
When our businesses enter into fixed-price long-term contracts to provide services or commodities, they are exposed to inflationary pressures such as rising commodity prices and interest rate risks.
Sempra Mexico and Sempra LNG generally endeavor to secure long-term contracts with customers for services and commodities to optimize the use of their facilities, reduce volatility in earnings and support the construction of new infrastructure. However, if these contracts are at fixed prices, the profitability of the contract may be materially adversely affected by inflationary pressures, including rising operational costs, costs of labor, materials, equipment and commodities, and rising interest rates that affect financing costs. We may try to mitigate these risks by using variable pricing tied to market indices, anticipating an escalation in costs when bidding on projects, providing for cost escalation, providing for direct pass-through of operating costs or entering into hedges. However, these measures, if implemented, may not ensure that the increase in revenues they provide will fully offset increases in operating expenses and/or financing costs. The failure to fully or substantially offset these increases could have a material adverse effect on our financial condition, cash flows and/or results of operations.
Increased competition and changes in trade policies 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 (including both domestic and international) and financial resources similar to or greater than ours. Further, in recent years, the natural gas pipeline, storage and LNG market segments have been characterized by strong and increasing competition both with respect to winning new development projects and acquiring existing assets. In Mexico, despite the commissioning of many new energy infrastructure projects by the CFE and other governmental agencies in connection with energy reforms, competition for recent pipeline projects has been intense with numerous bidders competing aggressively for these projects. There can be no assurance that we will be successful in bidding for new development opportunities in the U.S. and Mexico. These competitive factors could have a material adverse effect on our business, results of operations, cash flows and/or prospects.
In addition, the current U.S. Administration has indicated its intention to revise or replace international trade agreements, such as NAFTA. In November 2018, President Trump signed the USMCA, which, if approved by the legislatures of the U.S., Mexico and Canada, would replace NAFTA. The U.S. and Mexico approved the USMCA in January 2020 and June 2019, respectively, but Canada has yet to provide its approval. A shift in U.S. trade policies could materially adversely affect our LNG development opportunities, as well as opportunities for trade between Mexico and the U.S.
We may elect not to, or may not be able to, enter into, extend or replace expiring long-term supply and sales agreements or long-term firm capacity agreements for our projects, which would subject our revenues to increased volatility and our
businesses to increased competition. Such long-term contracts, once entered into, increase our credit risk if our counterparties fail to perform or become unable to meet their contractual obligations on a timely basis due to bankruptcy, insolvency, or otherwise.
The ECA LNG Regasification facility has long-term capacity agreements with a limited number of counterparties. Under these agreements, customers pay capacity reservation and usage fees to receive, store and regasify the customers’ LNG. We 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. The long-term supply agreement contracts are expected to reduce our exposure to changes in natural gas prices through corresponding natural gas sales agreements or by tying LNG supply prices to prevailing natural gas market price indices. If the counterparties, customers or suppliers to one or more of the key agreements for the ECA LNG Regasification facility were to fail to perform or become unable to meet their contractual obligations on a timely basis, it could have a material adverse effect on our results of operations, cash flows and/or prospects.
For the three-train liquefaction facility currently under construction by Cameron LNG, Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with affiliates of TOTAL S.A., Mitsubishi Corporation and Mitsui & Co., Ltd., that subscribe for the full nameplate capacity of the facility. If the counterparties to these tolling agreements were to fail to perform or become unable to meet their contractual obligations to Cameron LNG JV on a timely basis, it could have a material adverse effect on our results of operations, cash flows and/or prospects.
Sempra Mexico’s and Sempra LNG’s ability to enter into or replace existing long-term firm capacity agreements for their natural gas pipeline operations are dependent on demand for and supply of LNG and/or natural gas from their transportation customers, which may include our LNG facilities. A significant sustained decrease in demand for and supply of LNG and/or natural gas from such customers could have a material adverse effect on our businesses, results of operations, cash flows and/or prospects.
The electric generation and wholesale power sales industries are highly competitive. As more plants are built and competitive pressures increase, wholesale electricity prices may become more volatile. Without the benefit of long-term power sales agreements, our revenues may be subject to increased price volatility, and we may be unable to sell the power that Sempra Mexico’s facilities are capable of producing or to sell it at favorable prices, which could materially adversely affect our results of operations, cash flows and/or prospects.
Our businesses depend on counterparties, business partners, customers and suppliers performing in accordance with their agreements. If they fail to perform, we could incur substantial expenses and business disruptions and be exposed to commodity price risk and volatility, which could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.
Our businesses, and the businesses that we invest in, are exposed to the risk that counterparties, business partners, customers and suppliers that owe money or commodities as a result of market transactions or other long-term agreements or arrangements will not perform their obligations in accordance with such agreements or arrangements. Should they fail to perform, we may be required to enter into alternative arrangements or to honor the underlying commitment at then-current market prices. In such an event, we may incur additional losses to the extent of amounts already paid to such counterparties or suppliers. In addition, many such agreements are important for the conduct and growth of our businesses. The failure of any of the parties to perform in accordance with these agreements could materially adversely affect our businesses, results of operations, cash flows, financial condition and/or prospects. Finally, we often extend credit to counterparties and customers. While we perform significant credit analyses prior to extending credit, we are exposed to the risk that we may not be able to collect amounts owed to us.
Certain past assertions made by the CFE and Mexican government, coupled with past arbitration requests and other statements and actions by the CFE, raise serious concerns over whether the terms of Sempra Mexico’s gas pipeline contracts will be honored or disputed in arbitration. The failure by the CFE or other customers to honor the terms of Sempra Mexico’s gas pipeline contracts and the inability to enter into gas pipeline contracts in the future could have a material adverse effect on Sempra Energy’s cash flows, financial condition, results of operations and prospects.
Sempra Mexico’s and Sempra LNG’s obligations and those of their suppliers for LNG supplies are contractually subject to (1) suspension or termination for “force majeure” events beyond the control of the parties; and (2) substantial limitations of remedies for other failures to perform, including limitations on damages to amounts that could be substantially less than those necessary to provide full recovery of costs for breach of the agreements, which in either event could have a material adverse effect on our results of operations, cash flows, financial condition and/or prospects.
In addition, we may develop and/or own some projects with other equity owners and, therefore, we may not control all material decisions with respect to those projects, as is the case with the Cameron LNG JV project. To the extent that there is disagreement amongst the project equity owners with respect to certain decisions affecting such a project, the development, construction or
operation of such project may be delayed or otherwise materially adversely affected. Such a circumstance could materially adversely affect our business, financial condition, cash flows, result of operations and/or prospects.
Our businesses are subject to various legal actions challenging our property rights and permits.
We are engaged in disputes regarding our title to the properties adjacent to and properties where our ECA LNG Regasification facility and ECA LNG JV proposed liquefaction project in Mexico are located, as we discuss in Note 16 of the Notes to Consolidated Financial Statements. If we are unable to defend and retain title to the properties on which these current and proposed facilities are located, we could lose our rights to occupy and use such properties and the related facilities, which could result in breaches of one or more permits or contracts that we have entered into with respect to such facilities. In addition, our ability to construct an LNG liquefaction export facility may be hindered or halted by these disputes, and they could make project financing such a facility and finding suitable partners and customers very difficult. If we are unable to occupy and use such properties and the related facilities, it could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.
We rely on transportation assets and services, much of which we do not own or control, to deliver natural gas and electricity.
We depend on electric transmission lines, natural gas pipelines and other transportation facilities owned and operated by third parties to:
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deliver the natural gas and electricity we sell to wholesale markets or that we use for our liquefaction facilities;
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supply natural gas to our gas storage and electric generation facilities; and
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provide retail energy services to customers.
Sempra Mexico and Sempra LNG also depend on natural gas pipelines to interconnect with their ultimate source or customers of the commodities they are transporting. Sempra Mexico and Sempra LNG also rely on specialized ships to transport LNG to their facilities and on natural gas pipelines to transport natural gas for customers of the facilities. Sempra Mexico’s subsidiaries, as well as our South American businesses that are held for sale, rely on transmission lines to sell electricity to their customers. If transportation is disrupted, or if capacity is inadequate, we may be unable to sell and deliver our commodities, electricity and other services to some or all of our customers. As a result, we may be responsible for damages incurred by our customers, such as the additional cost of acquiring alternative electricity, natural gas supplies and LNG at then-current spot market rates, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
Our international businesses are exposed to different local, regulatory and business risks and challenges.
In Mexico, we own or have interests in natural gas distribution and transportation assets, LPG storage and transportation facilities, ethane transportation assets, electricity generation facilities, LNG facilities and ethane and liquid fuels marine and inland terminals. In Peru and Chile, we own or have interests in electric transmission, distribution and generation infrastructure and operations, which are held for sale. Developing infrastructure projects, owning energy assets and operating businesses in foreign jurisdictions subject us to significant security, political, legal, regulatory and financial risks that vary by country, including:
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changes in foreign laws and regulations, including tax and environmental laws and regulations, and U.S. laws and regulations, in each case, that are related to foreign operations;
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actions by local regulatory bodies, including setting of rates and tariffs that may be earned by our businesses;
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adverse changes in market conditions, trade restrictions, limitations on ownership in foreign countries and inadequate enforcement of regulations;
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foreign cash balances that may be unavailable to fund U.S. operations, or available only at unfavorable U.S. and/or foreign tax rates upon repatriation of such amounts or changes in tax law;
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permitting and regulatory compliance;
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adverse rulings by foreign courts or tribunals, challenges to permits and approvals, difficulty in enforcing contractual and property rights, and unsettled property rights and titles in Mexico;
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energy policy reform that may result in adverse changes to and/or difficulty in enforcing existing contracts, as we discuss below;
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expropriation or theft of assets;
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adverse changes in the stability of the governments in the countries in which we operate;
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social unrest; and
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compliance with the Foreign Corrupt Practices Act and similar laws.
In addition, the Mexican government has exercised, and continues to exercise, significant influence over the Mexican economy. Accordingly, Mexican governmental actions concerning the economy and certain governmental agencies, including the CFE
could have a significant impact on Mexican private sector entities in general and on IEnova’s operations in particular. For example, the CFE and the Mexican government took certain actions in 2019 that raised serious concerns over whether the terms of Sempra Mexico’s gas pipeline contracts would be honored or disputed in arbitration. IEnova and other affected natural gas pipeline developers joined the CFE and the President of Mexico’s representatives in negotiations and were able to resolve the dispute, but we cannot predict whether similar disputes may arise and/or whether such disputes will be resolved on favorable terms to us, if at all. We also cannot predict the impact that the political landscape, including multiparty rule and civil disobedience, will have on the Mexican economy. Such circumstances, may materially adversely affect our cash flows, financial condition, results of operations and/or prospects in Mexico, which could have a material adverse effect on Sempra’s consolidated financial statements.
We discuss litigation related to Sempra Mexico’s international energy projects in Note 16 of the Notes to Consolidated Financial Statements.
Other Risks
Sempra Energy has substantial investments in and obligations arising from businesses that it does not control or manage or in which it shares control.
Sempra Energy makes investments in entities that we do not control or manage or in which we share control. As described above, SDG&E holds a 20% ownership interest in SONGS, which is in the process of being decommissioned by Edison, its majority owner. As a result of ring-fencing measures, governance mechanisms and commitments, we account for our indirect, 100% ownership interest in Oncor Holdings, which, at December 31, 2019, owns an 80.25% interest in Oncor, as an equity method investment. Sempra LNG accounts for its 50.2% interest in Cameron LNG JV under the equity method. Sempra Mexico has a 40% interest in a JV with a subsidiary of TC Energy to build, own and operate the Sur de Texas-Tuxpan natural gas marine pipeline in Mexico, a 50% interest in a renewables wind project in Baja California, and a 50% interest in the Los Ramones Norte pipeline in Mexico. Sempra Energy has an equity method investment in the RBS Sempra Commodities partnership, which is in the process of being dissolved and for which Sempra Energy is subject to certain indemnities as we discuss in Note 16 of the Notes to Consolidated Financial Statements. Any adverse resolution of matters associated with our ownership interest in the RBS Sempra Commodities partnership could have a corresponding impact on our cash flows, financial condition and results of operations.
Sempra LNG provided guarantees related to Cameron LNG JV’s financing agreements, and Sempra Mexico has provided loans to JVs in which they have investments. We discuss the guarantees in Note 6 and affiliate loans in Note 1 of the Notes to Consolidated Financial Statements.
We have limited influence over these ventures and other businesses in which we do not have a controlling interest. In addition to the other risks inherent in these businesses, if their management were to fail to perform adequately or the other investors in the businesses were unable or otherwise failed to perform their obligations to provide capital and credit support for these businesses, it could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. We discuss our investments further in Notes 5, 6 and 12 of the Notes to Consolidated Financial Statements.
Market performance or changes in other assumptions could require Sempra Energy, SDG&E and/or SoCalGas to make significant unplanned contributions to their pension and other postretirement benefit plans.
Sempra Energy, SDG&E and SoCalGas provide defined benefit pension plans and other postretirement benefits to eligible employees and retirees. A decline in the market value of plan assets may increase the funding requirements for these plans. In addition, the cost of providing pension and other postretirement benefits is also affected by other factors, including the assumed rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, levels of assumed interest rates and future governmental regulation. An adverse change in any of these factors could cause a material increase in our funding obligations which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Impairment of goodwill would negatively impact our consolidated results of operations and net worth.
As of December 31, 2019, Sempra Energy had approximately $1,602 million of goodwill, which represented approximately 2.44% of the total assets on its Consolidated Balance Sheet, primarily related to the acquisitions of IEnova Pipelines and Ventika in Mexico. Goodwill is not amortized, but we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation, which could result in our recording a goodwill impairment loss. We discuss our annual goodwill impairment testing process and the factors considered in such testing in “Item 7. MD&A - Critical
Accounting Policies and Estimates” and in Note 1 of the Notes to Consolidated Financial Statements. A goodwill impairment loss could materially adversely affect our results of operations for the period in which such charge is recorded.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We own or lease land, warehouses, offices, operating and maintenance centers, shops, service facilities and equipment 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 “Item 1. Business” and Note 1 of the Notes to Consolidated Financial Statements.
ITEM 3.
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, “Item 1A. Risk Factors” and “Item 7. MD&A - Capital Resources and Liquidity.”
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II.
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION
Sempra Energy Common Stock
Our common stock is traded on the New York Stock Exchange under the ticker symbol SRE. At February 21, 2020, there were approximately 24,151 record holders of our common stock.
SoCalGas and SDG&E Common Stock
Information concerning dividend declarations for SoCalGas and SDG&E is included in their Statements of Changes in Shareholders’ Equity and Statements of Changes in Equity, respectively, set forth in the Consolidated Financial Statements.
Dividend Restrictions
The payment and the amount of future dividends for Sempra Energy, SDG&E, and SoCalGas are within the discretion of their boards of directors. The CPUC’s regulation of the California Utilities’ capital structures limits the amounts that the California Utilities can pay Sempra Energy in the form of loans and dividends. We discuss these matters in Note 1 of the Notes to Consolidated Financial Statements in “Restricted Net Assets” and in “Item 7. MD&A - Capital Resources and Liquidity - Dividends.”
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
On September 11, 2007, the Sempra Energy board of directors authorized the repurchase of Sempra Energy 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. No shares have been repurchased under this authorization since 2011. Approximately $500 million remains authorized by our board of directors for the purchase of additional shares, not to exceed approximately 12 million shares.
We also may, 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.
ITEM 6. SELECTED FINANCIAL DATA
FIVE-YEAR SUMMARIES
The following tables present selected financial data of Sempra Energy, SDG&E and SoCalGas for the five years ended December 31, 2019. The data is derived from the audited consolidated financial statements of each company. You should read this information in conjunction with “Item 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
In 2018, we set out to simplify Sempra Energy’s business model and sharpen our focus on building North America’s premier energy infrastructure company. Our 2019 operational and financial results reflect our focus on executing this strategy:
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The California Utilities received a constructive final GRC decision for the 2019 revenue requirement and attrition year adjustments for 2020 and 2021, and a final decision in the 2020 cost of capital proceeding.
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SDG&E contributed to the Wildfire Fund that was created through the Wildfire Legislation that addresses certain issues related to catastrophic wildfires in California.
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We supported Oncor’s acquisition of InfraREIT and acquired an indirect 50% interest in Sharyland Holdings in Texas.
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Cameron LNG JV’s Train 1 commenced commercial operation.
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We sold our non-utility natural gas storage assets in the southeast U.S. (comprised of Mississippi Hub and Bay Gas) and our remaining U.S. wind assets and investments. In April 2019, our Sempra Renewables segment ceased to exist.
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We entered into agreements to sell our equity interests in our South American businesses, which were previously included in our Sempra South American Utilities segment, and expect those sales to close in the first half of 2020.
Our South American businesses and certain activities associated with those businesses have been reclassified to discontinued operations for all periods presented. Nominal activities that are not classified as discontinued operations have been subsumed into Parent and other. Our discussions below exclude discontinued operations, unless otherwise noted.
RESULTS OF OPERATIONS
We discuss the following in Results of Operations:
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Overall results of operations of Sempra Energy
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Segment results
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Significant changes in revenues, costs and earnings
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Impact of foreign currency and inflation rates on results of operations
OVERALL RESULTS OF OPERATIONS OF SEMPRA ENERGY
In 2019, our earnings increased by approximately $1,131 million to $2,055 million and our diluted EPS increased by $3.87 to $7.29. In 2018 compared to 2017, our earnings increased by $668 million to $924 million and our diluted EPS increased by $2.41 to $3.42. The change in diluted EPS for 2019 and 2018 included decreases of $(0.33) and $(0.24), respectively, attributable to an increase in weighted-average common shares outstanding. Our earnings and diluted EPS were impacted by variances discussed in “Segment Results” below.
SEGMENT RESULTS
The following section presents earnings (losses) by Sempra Energy segment, as well as Parent and other, and the 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. As we discuss below in “Significant Changes in Revenues, Costs and Earnings - Income Taxes,” in December 2017, the TCJA was signed into law. The TCJA reduced the U.S. statutory corporate federal income tax rate from 35% to 21%, effective January 1, 2018. After-tax variances between 2018 and 2017 assume that amounts in both years were taxed at the 2017 statutory rate.
(1)
Includes $914 million income tax expense from the effects of the TCJA in 2017, intercompany eliminations recorded in consolidation and certain corporate costs.
SDG&E
The increase in earnings of $98 million (15%) in 2019 was primarily due to:
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$71 million higher CPUC base operating margin authorized for 2019, net of operating expenses;
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$31 million income tax benefit 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; and
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$11 million higher margin from electric transmission operations, net of a FERC formulaic rate adjustment benefit in 2018; offset by
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$10 million amortization of Wildfire Fund asset.
The increase in earnings of $262 million in 2018 compared to 2017 was primarily due to:
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$208 million charge in 2017 for the write-off of a regulatory asset associated with 2007 wildfire costs;
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$65 million higher margin from electric transmission operations in 2018, including the annual FERC formulaic rate adjustment;
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$28 million unfavorable impact in 2017 from the remeasurement of certain U.S. federal deferred income tax assets as a result of the TCJA; and
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$27 million higher CPUC base operating margin authorized for 2018, primarily related to the lower federal income tax rate in 2018; offset by
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$35 million higher net interest expense, of which $25 million relates to the lower federal income tax rate in 2018; and
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$11 million unfavorable impact due to lower cost of capital related to GRC base business, which excludes incremental projects and other balanced capital programs, in 2018, of which $2 million relates to the lower federal income tax rate in 2018.
SoCalGas
The increase in earnings of $241 million in 2019 was primarily due to:
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$216 million higher CPUC base operating margin authorized for 2019, net of operating expenses;
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$38 million income tax benefit from the impact of the January 2019 CPUC decision allocating certain excess deferred income tax balances to shareholders;
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$22 million from impacts associated with Aliso Canyon natural gas storage facility litigation in 2018; and
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$14 million higher income tax benefits from flow-through items; offset by
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$21 million impairment of non-utility native gas assets in 2019;
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$18 million higher net interest expense; and
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$8 million penalties in 2019 related to the SoCalGas billing practices OII.
The increase in earnings of $4 million (1%) in 2018 compared to 2017 was primarily due to:
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$36 million higher CPUC base operating margin authorized for 2018, net of expenses including depreciation (of this increase, $28 million relates to the lower federal income tax rate in 2018); and
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$16 million higher PSEP earnings; offset by
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$22 million higher net interest expense, of which $15 million relates to the lower federal income tax rate in 2018;
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$21 million unfavorable impact due to lower cost of capital related to GRC base business in 2018, of which $4 million relates to the lower federal income tax rate in 2018; and
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$22 million in 2018 from impacts associated with Aliso Canyon natural gas storage facility litigation compared to $20 million in 2017.
Sempra Texas Utilities
The increase in earnings of $157 million (42%) in 2019 primarily represents higher equity earnings from Oncor Holdings, which we acquired in March 2018, driven by the impact of Oncor’s acquisition of InfraREIT in May 2019 and higher revenues due to rate updates to reflect increases in invested transmission capital, partially offset by higher operating costs.
Earnings of $371 million in 2018 represent equity earnings from our investment in Oncor Holdings.
Sempra Mexico
The increase in earnings of $16 million (7%) in 2019 was primarily due to:
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$18 million primarily due to the start of commercial operations of the Sur de Texas-Tuxpan marine pipeline at IMG JV in the third quarter of 2019;
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$16 million lower income tax expense in 2019 primarily from a two-year tax abatement that expires in 2020; and
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$122 million earnings attributable to NCI at IEnova in 2019 compared to $132 million earnings in 2018; offset by
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$20 million lower earnings primarily from force majeure payments that ended on August 22, 2019 with respect to the Guaymas-El Oro segment of the Sonora pipeline; and
▪
$17 million unfavorable impact from foreign currency and inflation effects, net of foreign currency derivatives effects, comprised of:
◦
in 2019, $88 million unfavorable foreign currency and inflation effects, offset by a $29 million gain from foreign currency derivatives, offset by
◦
in 2018, $43 million unfavorable foreign currency and inflation effects, offset by a $1 million gain from foreign currency derivatives (we discuss these effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.”)
The increase in earnings of $68 million (40%) in 2018 compared to 2017 was primarily due to:
▪
$107 million higher earnings at TdM, including $71 million impairment in 2017 of assets that were held for sale until June 1, 2018 and $32 million improved operating results primarily as a result of major maintenance in 2017 and higher revenues in 2018;
▪
$37 million higher earnings, primarily attributable to pipeline assets placed in service in the second quarter of 2017 and IEnova’s increased indirect ownership interest in TAG JV; and
▪
$10 million improved operating results at Ecogas, mainly due to new rates approved by the CRE and regulated revenues associated with recovery for revised tariffs; offset by
▪
$132 million earnings attributable to NCI at IEnova in 2018 compared to $73 million in 2017;
▪
$22 million lower capitalized financing costs, primarily associated with assets placed in service at the end of the first half of 2017, net of higher equity earnings in 2018 from AFUDC at IMG JV; and
▪
$7 million unfavorable impact from foreign currency and inflation effects, net of foreign currency derivatives effects, comprised of:
◦
in 2018, $43 million unfavorable foreign currency and inflation effects, offset by a $1 million gain from foreign currency derivatives, offset by
◦
in 2017, $84 million unfavorable foreign currency and inflation effects, offset by a $49 million gain from foreign currency derivatives.
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.
The decrease in earnings of $269 million in 2019 was primarily due to:
▪
$367 million gain on the sale of all Sempra Renewables’ operating solar assets, solar and battery storage development projects and its 50% interest in a wind power generation facility in December 2018; and
▪
$92 million lower earnings from assets sold in December 2018 and April 2019, net of lower general and administrative and other costs due to the wind-down of this business; offset by
▪
$145 million other-than-temporary impairment of certain U.S. wind equity method investments in 2018; and
▪
$45 million gain on sale of Sempra Renewables’ remaining wind assets in 2019.
The increase in earnings of $76 million (30%) in 2018 compared to 2017 was primarily due to:
▪
$367 million gain on the sale of all Sempra Renewables’ operating solar assets, solar and battery storage development projects and its 50% interest in a wind power generation facility in December 2018;
▪
$35 million higher pretax losses attributed to NCI, including the impact of the TCJA on NCI allocations computed using the HLBV method; and
▪
$19 million lower depreciation as a result of solar and wind assets held for sale; offset by
▪
$192 million favorable impact in 2017 from the remeasurement of U.S. federal deferred income tax liabilities as a result of the TCJA; and
▪
$145 million other-than-temporary impairment of certain U.S. wind equity method investments in 2018.
Sempra LNG
The decrease in losses of $611 million in 2019 was primarily due to:
▪
$665 million net impairment of certain non-utility natural gas storage assets in the southeast U.S. in 2018, including $801 million impairment in the second quarter of 2018, offset by a $136 million reduction to the impairment in the fourth quarter of 2018;
▪
$17 million higher equity earnings from Cameron LNG JV, including:
◦
$36 million increase primarily due to Train 1 commencing commercial operation under its tolling agreements in August 2019, offset by
◦
$19 million decrease due to the write-off of unamortized debt issuance costs and associated fees related to Cameron LNG JV’s debt refinancing; and
▪
$9 million unfavorable adjustment in 2018 to TCJA provisional amounts recorded in 2017 related to the remeasurement of deferred income taxes; offset by
▪
$36 million losses attributable to NCI in 2018 related to the net impairment discussed above; and
▪
$28 million higher liquefaction project development costs and operating costs.
Losses of $617 million in 2018 compared to earnings of $150 million in 2017 were primarily due to:
▪
$665 million net impairment of certain non-utility natural gas storage assets in 2018;
▪
$142 million higher income tax expense in 2018, which included $133 million favorable impact in 2017 from the remeasurement of U.S. federal deferred income tax liabilities as a result of the TCJA and $9 million unfavorable impact in 2018 to adjust TCJA provisional amounts recorded in 2017; and
▪
$34 million settlement proceeds in 2017 from a breach of contract claim against a counterparty in bankruptcy court, of which $28 million related to a charge in 2016 from the permanent release of certain pipeline capacity; offset by
▪
$36 million losses attributable to NCI in 2018 related to the net impairment discussed above;
▪
$24 million higher earnings from midstream activities primarily driven by lower depreciation and amortization as a result of natural gas storage assets held for sale; and
▪
$15 million improved results in 2018 from LNG marketing activities.
Parent and Other
The decrease in losses of $105 million (17%) in 2019 was primarily due to:
▪
$65 million impairment of the RBS Sempra Commodities equity method investment in 2018;
▪
$48 million higher investment gains in 2019 on dedicated assets in support of our employee nonqualified benefit plan obligations, net of deferred compensation expenses;
▪
$32 million income tax expense in 2018 to adjust provisional amounts recorded in 2017 related to the TCJA; and
▪
$10 million income tax benefit in 2019 to reduce a valuation allowance against certain NOL carryforwards as a result of our decision to sell our South American businesses; offset by
▪
$17 million increase in mandatory convertible preferred stock dividends primarily from the issuance of series B preferred stock in July 2018;
▪
$11 million increase primarily related to settlement charges from our nonqualified pension plan; and
▪
$11 million loss from foreign currency derivatives used to hedge exposure to fluctuations in the Peruvian Sol related to the sale of our operations in Peru.
The decrease in losses of $440 million (42%) in 2018 compared to 2017 was primarily due to:
▪
$914 million unfavorable impact in 2017 from the TCJA, offset by $32 million income tax expense in 2018 to adjust provisional amounts recorded in 2017 (we discuss the impacts from the TCJA in “Significant Changes in Revenues, Costs and Earnings - Income Taxes” below); offset by
▪
$179 million increase in net interest expense, of which $58 million relates to the lower tax rate in 2018;
▪
$125 million mandatory convertible preferred stock dividends declared;
▪
$65 million impairment of the RBS Sempra Commodities equity method investment; and
▪
$15 million investment losses in 2018 compared to $41 million investment gains in 2017 on dedicated assets in support of our employee nonqualified benefit plan obligations, net of deferred compensation expenses.
Discontinued Operations
Discontinued operations that were previously in our Sempra South American Utilities segment include our 100% interest in Chilquinta Energía in Chile, our 83.6% interest in Luz del Sur in Peru and our 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.
The increase in earnings of $172 million in 2019 was primarily due to:
▪
$91 million higher earnings from South American operations mainly from higher rates, lower cost of purchased power at Peru, and including $38 million lower depreciation expense due to assets classified as held for sale;
▪
$89 million income tax benefit in 2019 from outside basis differences in our South American businesses primarily related to the change in our indefinite reinvestment assertion from our decision on January 25, 2019 to hold those businesses for sale and a change in the anticipated structure of the sale; and
▪
$44 million income tax expense in 2018 to adjust TCJA provisional amounts recorded in 2017 primarily related to withholding tax on our expected future repatriation of foreign undistributed earnings; offset by
▪
$51 million income tax expense related to the increase in outside basis differences from 2019 earnings since January 25, 2019.
Earnings of $156 million in 2018 compared to losses of $58 million in 2017 were primarily due to a $251 million unfavorable impact in 2017 from the TCJA, offset by $44 million income tax expense in 2018 to adjust provisional amounts recorded in 2017.
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 Energy, SDG&E and SoCalGas.
Utilities Revenues
Our utilities revenues include natural gas revenues at our California Utilities and Sempra Mexico’s Ecogas and electric revenues at SDG&E. Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy 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. However, 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. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements and in “Item 1. Business - Ratemaking Mechanisms.”
▪
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.
▪
The California Utilities to recover certain expenses for programs 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 customer billing cycles causing a difference between customer billings and recorded or authorized costs. 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.
The table below summarizes utilities revenues and cost of sales.
Natural Gas Revenues and Cost of Natural Gas
The table below summarizes the average cost of natural gas sold by the California Utilities 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 2019, our natural gas revenues increased by $645 million (14%) to $5.2 billion primarily due to:
▪
$563 million increase at SoCalGas, which included:
◦
$383 million higher authorized revenue in 2019,
◦
$105 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M,
◦
$62 million higher non-service component of net periodic benefit cost in 2019, which fully offsets in Other Income, Net,
◦
$29 million charges in 2018 associated with tracking the income tax benefit from flow-through items in relation to forecasted amounts in the 2016 GRC FD, and
◦
$16 million higher net revenues from PSEP, offset by
◦
$71 million decrease in the cost of natural gas sold, which we discuss below; and
▪
$93 million increase at SDG&E, which included:
◦
$68 million higher authorized revenue in 2019, and
◦
$24 million increase in the cost of natural gas sold, which we discuss below.
In 2018 compared to 2017, our natural gas revenues increased by $179 million (4%) to $4.5 billion primarily due to:
▪
$177 million increase at SoCalGas, which included:
◦
$160 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M,
◦
$71 million increase in 2018 due to an increase in rates permitted under the attrition mechanism in the 2016 GRC FD,
◦
$23 million increase in cost of natural gas sold, and
◦
$19 million decrease in charges in 2018 associated with tracking the income tax benefit from flow-through items in relation to forecasted amounts in the 2016 GRC FD, offset by
◦
$67 million revenue deferral due to the effect of the TCJA,
◦
$29 million lower cost of capital related to GRC base business in 2018, and
◦
$10 million lower net revenues from capital projects, including $60 million decrease for advanced metering infrastructure due to completion of the project, offset by increases of $14 million for PSEP and $36 million for other capital projects; and
▪
$24 million increase at SDG&E primarily due to higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are offset in O&M, and 2018 attrition; offset by
▪
$32 million decrease at Sempra Mexico, which included:
◦
$46 million lower volumes at Ecogas primarily as a result of the new regulations that went into effect on March 1, 2018 that no longer allow Ecogas to sell natural gas to high consumption end users (defined by the CRE as customers with annual consumption that exceeds 4,735 MMBtu) and require those end users to procure their natural gas needs from natural gas marketers, including Sempra Mexico’s marketing business, offset by
◦
$13 million higher rates approved by the CRE, including $7 million from a regulatory adjustment to rates charged to end users in 2014 through 2016.
Our cost of natural gas decreased by $69 million (6%) to $1.1 billion in 2019 primarily due to:
▪
$71 million decrease at SoCalGas, including $164 million due to lower average natural gas prices, offset by $93 million from higher volumes driven by weather; and
▪
$15 million increase in intercompany eliminations primarily associated with sales between Sempra LNG and SoCalGas; offset by
▪
$24 million increase at SDG&E, including $19 million from higher volumes driven by weather and $5 million from higher average natural gas prices.
Our cost of natural gas increased by $18 million (2%), remaining at $1.2 billion in 2018 compared to 2017, primarily due to:
▪
$56 million increase primarily from lower elimination of intercompany costs at Sempra Mexico; and
▪
$23 million increase at SoCalGas due to $43 million from higher average gas prices, offset by $20 million from lower volumes driven by weather; offset by
▪
$49 million decrease at Sempra Mexico primarily associated with the lower revenues at Ecogas; and
▪
$12 million decrease at SDG&E primarily due to lower average gas prices.
Electric Revenues and Cost of Electric Fuel and Purchased Power
Our electric revenues increased by $264 million (7%) to $4.3 billion in 2019 primarily attributable to SDG&E, including:
▪
$121 million higher authorized revenue in 2019, including $108 million of revenues to cover liability insurance premium costs that are now balanced and offset in O&M;
▪
$40 million higher revenues from transmission operations, net of a FERC formulaic rate adjustment benefit in 2018;
▪
$34 million higher recovery of costs associated with CPUC-authorized refundable programs, excluding 2019 liability insurance premium costs, which revenues are offset in O&M;
▪
$27 million higher finance lease costs, offset by lower cost of electric fuel and purchased power, which we discuss below; and
▪
$21 million charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD.
In 2018 compared to 2017, our electric revenues increased by $70 million (2%) to $4.0 billion primarily attributable to SDG&E, including:
▪
$77 million higher cost of electric fuel and purchased power;
▪
$50 million higher revenues from transmission operations, including the annual FERC formulaic rate adjustment;
▪
$32 million decrease in charges in 2018 associated with tracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD; and
▪
$32 million increase due to 2018 attrition; offset by
▪
$65 million revenue deferral due to the effect of the TCJA;
▪
$39 million revenue deferral related to the SONGS settlement, which is offset by the discontinuation of amortization; and
▪
$13 million lower cost of capital related to the CPUC base business in 2018.
Our utility cost of electric fuel and purchased power decreased by $170 million (13%) to $1.2 billion in 2019, primarily attributable to SDG&E, including:
▪
$103 million of finance lease costs for PPAs in 2018. Similar amounts are now included in Interest Expense and Depreciation and Amortization Expense as a result of the 2019 adoption of the lease standard; and
▪
$73 million decrease primarily from lower electricity market cost, offset by an increase primarily due to an additional capacity contract.
Our utility cost of electric fuel and purchased power increased by $65 million (5%) to $1.4 billion in 2018 compared to 2017 primarily attributable to SDG&E, driven primarily by higher gas prices and electricity market costs, partially offset by lower cost of purchased power from renewable sources due to decreased solar and wind production and from lower capacity contract costs.
Energy-Related Businesses: Revenues and Cost of Sales
The table below shows revenues and cost of sales for our energy-related businesses.
(1)
Excludes depreciation and amortization, which are presented separately on the Sempra Energy Consolidated Statements of Operations.
(2)
Includes eliminations of intercompany activity.
Revenues from our energy-related businesses decreased by $182 million (12%) to $1.4 billion in 2019 while the related cost of sales for 2019 was comparable to 2018. The decrease in revenues included:
▪
$114 million decrease at Sempra Renewables primarily due to the sale of assets in December 2018 and April 2019; and
▪
$62 million decrease at Sempra LNG primarily due to:
◦
$45 million lower natural gas storage revenues primarily due to the sale of storage assets in February 2019,
◦
$15 million from the marketing business due to lower turnback cargo revenues, and
◦
$12 million from LNG sales to Cameron LNG JV in January 2018, offset by
◦
$14 million from natural gas marketing activities primarily due to changes in natural gas prices; offset by
▪
$4 million increase at Sempra Mexico primarily due to:
◦
$23 million from the marketing business, including an increase in volumes due to new regulations that went into effect on March 1, 2018 that require high consumption end users (previously serviced by Ecogas and other natural gas utilities) to procure their natural gas needs from natural gas marketers, such as Sempra Mexico’s marketing business, offset by lower natural gas prices, and
◦
$6 million increase primarily due to renewable assets placed in service in 2019, offset by
◦
$27 million lower revenues primarily from force majeure payments that ended on August 22, 2019 with respect to the Guaymas-El Oro segment of the Sonora pipeline.
In 2018 compared to 2017, revenues from our energy-related businesses increased by $213 million (16%) to $1.6 billion. The increase included:
▪
$212 million increase at Sempra Mexico primarily due to:
◦
$84 million from the marketing business, primarily due to new regulations that went into effect on March 1, 2018 and from higher volumes and gas prices,
◦
$69 million at TdM primarily due to the plant outage in 2017 as a result of scheduled major maintenance and higher power prices,
◦
$34 million primarily due to pipeline assets placed in service in the second quarter of 2017, and
◦
$18 million from O&M services provided to the TAG JV;
▪
$39 million increase from lower intercompany eliminations associated with sales between Sempra LNG and Sempra Mexico; and
▪
$30 million increase at Sempra Renewables primarily due to solar and wind assets placed in service in the fourth quarter of 2017 and the second quarter of 2018; offset by
▪
$68 million decrease at Sempra LNG primarily due to:
◦
$98 million costs associated with indemnity payments to Sempra Mexico in 2018. Indemnity payments of $103 million in 2017 were recorded in Energy-Related Businesses Cost of Sales prior to adoption of ASC 606, offset by
◦
$50 million from the marketing business primarily from higher natural gas sales and turnback cargo revenues.
The cost of sales for our energy-related businesses increased by $66 million (23%) to $357 million in 2018 compared to 2017 primarily due to:
▪
$102 million at Sempra Mexico primarily associated with higher revenues from the marketing business as a result of the new regulations that went into effect on March 1, 2018. The increase at Sempra Mexico was also due to higher volumes in 2018 due to the TdM plant outage in 2017;
▪
$57 million in settlement proceeds received by Sempra LNG in May 2017 from a breach of contract claim against a counterparty, of which $47 million is related to a charge in 2016 from permanent release of pipeline capacity; and
▪
$4 million lower intercompany eliminations of costs between Sempra LNG and Sempra Mexico, including $103 million elimination of indemnity payments made by Sempra LNG in 2017 now recorded as a reduction to Energy-Related Business Revenues since adoption of ASC 606; offset by
▪
$88 million decrease at Sempra LNG primarily due to indemnity payments to Sempra Mexico in 2017 recorded in revenue in 2018 pursuant to adoption of ASC 606.
Operation and Maintenance
In the table below, we provide O&M by segment.
(1)
Excludes $6 million of impairment losses, which we discuss below.
(2)
Includes eliminations of intercompany activity.
Our O&M increased by $316 million (10%) to $3.5 billion in 2019 primarily due to:
▪
$167 million increase at SoCalGas, which included:
◦
$105 million higher expenses associated with CPUC-authorized refundable programs for which costs incurred are recovered in revenue (refundable program expenses), and
◦
$57 million higher non-refundable operating costs, including labor, contract services and administrative and support costs;
▪
$117 million increase at SDG&E which included:
◦
$147 million higher expenses associated with CPUC-authorized refundable programs, including $112 million of 2019 liability insurance premium costs that are now balanced in revenue, and
◦
$12 million amortization of Wildfire Fund asset, offset by
◦
$46 million lower non-refundable operating costs, including $87 million decrease from liability insurance premium costs for 2018 that were not balanced, offset by $41 million of higher operating costs;
▪
$53 million increase at Parent and other primarily from higher deferred compensation expense;
▪
$33 million increase at Sempra LNG primarily from higher liquefaction development project costs and higher operating costs; and
▪
$17 million increase at Sempra Mexico primarily due to expenses associated with growth in the business and operating lease costs in 2019; offset by
▪
$71 million decrease at Sempra Renewables primarily due to lower general and administrative and other costs due to the wind-down of the business.
Our O&M increased by $203 million (7%) to $3.2 billion in 2018 compared to 2017 primarily due to:
▪
$139 million increase at SoCalGas, which included:
◦
$160 million higher expenses associated with CPUC-authorized refundable programs, offset by
◦
$20 million Aliso Canyon litigation reserves in 2017;
▪
$34 million increase at SDG&E, which included:
◦
$22 million higher non-refundable operating costs, including labor, contract services and administrative and support costs, and
◦
$11 million reimbursement of litigation costs in 2017 associated with the arbitration ruling over the SONGS replacement steam generators; and
▪
$16 million increase at Sempra Renewables primarily due to solar and wind assets placed in service in the fourth quarter of 2017 and the second quarter of 2018 and selling costs associated with the sale of assets.
Write-Off of Wildfire Regulatory Asset
In 2017, SDG&E recorded a $351 million charge for the write-off of a regulatory asset associated with 2007 wildfire costs. We discuss this further 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, and SDG&E and SoCalGas recognized impairment losses of $6 million and $8 million, respectively, for certain disallowed capital costs in the 2019 GRC FD. In 2018, Sempra LNG recognized a $1.1 billion net impairment loss for certain non-utility natural gas storage assets in the southeast U.S. In 2017, Sempra Mexico reduced the carrying value of TdM by recognizing noncash impairment charges of $71 million.
Gain on Sale of Assets
In April 2019, Sempra Renewables recognized a $61 million gain on the sale of its remaining wind assets and investments to AEP. In December 2018, Sempra Renewables recognized a $513 million gain on the sale of all its operating solar assets, solar and battery storage development projects and its 50% interest in a wind power generation facility to a subsidiary of Con Ed.
Other Income, Net
As part of our central risk management function, we enter into foreign currency derivatives to hedge Sempra Mexico parent’s 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, Net, as described below, and partially mitigate the transactional effects of foreign currency and inflation included in Income Tax (Expense) Benefit for Sempra Mexico’s consolidated entities and in Equity Earnings for Sempra Mexico’s equity method investments. We also utilize foreign currency derivatives to hedge exposure to fluctuations in the Peruvian Sol related to the sale of our operations in Peru. We discuss policies governing our risk management below in “Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk of erosion of our cash flows, earnings, asset values and equity due to adverse changes in market prices, interest rates and foreign currency rates.
RISK POLICIES
Sempra Energy has policies governing its market risk management and trading activities. Sempra Energy and the California Utilities maintain separate risk management committees, organizations and processes for the California Utilities and for all non-CPUC regulated affiliates to provide oversight of these activities. The committees consist of senior officers who establish policy, oversee energy risk management activities, and monitor the results of trading and other activities to 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 the energy procurement departments.
Along with other tools, we use VaR and liquidity metrics to measure our exposure to market risk associated with the 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 calculated independently by the respective risk management oversight organizations.
The California Utilities use power and natural gas derivatives to manage natural gas and electric 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 the 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 rates. The following discussion of these primary market-risk exposures as of December 31, 2019 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 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 unique markets and operating and regulatory environments of each subsidiary.
Sempra Mexico and Sempra LNG are generally exposed to commodity price risk indirectly through their LNG, natural gas pipelines and storage, and power-generating assets. These segments may utilize commodity transactions in the course of optimizing 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 not have resulted in a material change in the fair value of our commodity-based derivatives for these segments at December 31, 2019 and 2018. 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.
The California Utilities’ 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 incentive mechanisms that reward or penalize the utility for commodity costs below or above certain benchmarks for SoCalGas’ GCIM. If commodity prices were to rise too rapidly, it is likely that volumes would decline. This decline would increase the per-unit fixed costs, which could lead to further volume declines. The California Utilities manage their risk within the parameters of their market risk management framework. As of and for the year ended December 31, 2019, the total VaR of the California Utilities’ natural gas and electric positions was not material, and the procurement activities were in compliance with the procurement plans filed with and approved by the CPUC.
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 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 and build-to-suit arrangement.
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 long-term debt. If weighted-average interest rates on short-term debt outstanding at December 31, 2019 increased or decreased by 10%, the change in earnings over the 12-month period ended December 31, 2020 would be approximately $8 million. If interest rates increased or decreased by 10% on all variable-rate long-term debt at December 31, 2019, after
considering the effects of interest rate swaps, the change in earnings over the 12-month period ended December 31, 2020 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 the California Utilities, to be recovered in future rates.
FOREIGN CURRENCY AND INFLATION RATE RISK
We discuss the impact of foreign currency and inflation rates in “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)
Amount represents the impact to earnings for a change in the average exchange rate throughout the reporting period.
(2)
Amount primarily represents the effects of currency exchange rate movement from December 31, 2019 on monetary assets and liabilities and translation of non-U.S. deferred income tax balances at our Mexican subsidiaries.
(3)
Amount represents the effects of currency exchange rate movement from December 31, 2019 recorded to OCI at the end of each reporting period.
Monetary assets and liabilities at our Mexican subsidiaries 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 $4.0 billion, including those related to our investments in JVs, at December 31, 2019, the hypothetical effect of a 10% increase in the Mexican inflation rate is approximately $77 million lower earnings as a result of higher income tax expense for our consolidated subsidiaries, as well as lower equity earnings for our JVs.
ITEM 8.
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Sempra Energy, SDG&E, SoCalGas
Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports 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 other possible controls and procedures.
Under the supervision and with the participation of management, including the principal executive officers and principal financial officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2019, the end of the period covered by this report. Based on these evaluations, the principal executive officers and principal financial officers of Sempra Energy, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Sempra Energy, SDG&E, SoCalGas
The respective management of each company 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 management of each company, including each company’s principal executive officer and principal financial officer, the effectiveness of each company’s internal control over financial reporting was evaluated based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluations, each company concluded that its internal control over financial reporting was effective as of December 31, 2019. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2019, as stated in their reports, which are included in this annual report on Form 10-K.
There have been no changes in the companies’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the companies’ 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 Energy”) as of December 31, 2019, 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 Energy maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, 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, 2019, of Sempra Energy and our report dated February 27, 2020, expressed an unqualified opinion on those financial statements.
Basis for Opinion
Sempra Energy’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 Energy’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 Energy 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 27, 2020
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, 2019, 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, 2019, 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, 2019, of SDG&E and our report dated February 27, 2020, 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 27, 2020
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, 2019, 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, 2019, 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, 2019, of SoCalGas and our report dated February 27, 2020, 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 the 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 27, 2020
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
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 Items 10, 11, 12 and 13 below is not required for SDG&E. We have, however, provided the information required by Item 10
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
We provide the information required by Item 10 with respect to executive officers for Sempra Energy and SoCalGas in “Item 1. Business - Other Matters - Information About Our Executive Officers.” For Sempra Energy, all other information required by Item 10 is incorporated by reference from “Corporate Governance” and “Share Ownership” in the Proxy Statement to be filed for its May 2020 annual meeting of shareholders. For SoCalGas, all other information required by Item 10 is incorporated by reference from its Information Statement to be filed for its May 2020 annual meeting of shareholders. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from “Corporate Governance” and “Executive Compensation,” including “Compensation Discussion and Analysis,” “Compensation Committee Report” and “Compensation Tables” in the Proxy Statement to be filed for the May 2020 annual meeting of shareholders for Sempra Energy and from the Information Statement to be filed for the May 2020 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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
Sempra Energy 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, 2019, outstanding awards consisted of stock options and RSUs held by 429 employees.
The following table sets forth information regarding our equity compensation plan at December 31, 2019.
(1)
The 2013 LTIP consists of 247,577 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, 1,086,981 performance-based RSUs and 378,139 service-based RSUs. Each performance-based RSU represents the right to receive from zero to 2.0 shares of our common stock if applicable performance conditions are satisfied. No new awards may be granted under the 2013 LTIP. The 2019 LTIP consists of 37,648 service-based RSUs.
(2)
Represents only the weighted-average exercise price of the 247,577 outstanding options to purchase shares of our common stock under the 2013 LTIP. No options have been issued under the 2019 LTIP.
(3)
The number of shares available for future issuance is increased by the number of shares to which the 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 or other previous shareholder-approved LTIPs.
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 security ownership information required by Item 12 is incorporated by reference from “Share Ownership” in the Proxy Statement to be filed for the May 2020 annual meeting of shareholders for Sempra Energy and in the Information Statement to be filed for the May 2020 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated by reference from “Corporate Governance” in the Proxy Statement to be filed for the May 2020 annual meeting of shareholders for Sempra Energy and from the Information Statement to be filed for the May 2020 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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services is presented below for Sempra Energy, SDG&E and SoCalGas. The following table shows the fees paid to Deloitte & Touche LLP, the independent registered public accounting firm for Sempra Energy, SDG&E and SoCalGas, for services provided for 2019 and 2018.
The Audit Committee of Sempra Energy’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 Energy and its subsidiaries, including SDG&E and SoCalGas. As a matter of good corporate governance, each of the Sempra Energy, 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 Energy, SDG&E and SoCalGas, respectively. Sempra Energy’s board of directors has determined that each member of its Audit Committee is an independent director and is financially literate, and that Mr. Taylor, the chair of the committee, is an audit committee financial expert as defined by the rules of the SEC.
Except where pre-approval is not required by SEC rules, Sempra Energy’s Audit Committee pre-approves all audit, audit-related and permissible non-audit services provided by Deloitte & Touche LLP for Sempra Energy and its subsidiaries, including all services provided by Deloitte & Touche LLP for Sempra Energy, SDG&E and SoCalGas in 2019 and 2018. 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. 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 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.
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 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 EDGAR.
* Certain sensitive personally identifiable information in this exhibit was omitted by means of redacting a portion of the text and replacing it with [***].
(1) Exhibit is not available on the SEC’s website as it was filed in paper and predates EDGAR.
(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.
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/ Kevin C. Sagara
Kevin C. Sagara
Chairman and Chief Executive Officer
Date: February 27, 2020
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/ J. Bret Lane
J. Bret Lane
Chairman and Chief Executive Officer
Date: February 27, 2020
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 Energy”) as of December 31, 2019 and 2018, 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, 2019, and 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 Energy as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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 Energy’s internal control over financial reporting as of December 31, 2019, 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 27, 2020, expressed an unqualified opinion on Sempra Energy’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of Sempra Energy’s management. Our responsibility is to express an opinion on Sempra Energy’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 Energy 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 for Aliso Canyon Costs - Refer to Note 16 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
Sempra Energy has an insurance receivable of $339 million as of December 31, 2019, related to certain costs arising from the Aliso Canyon natural gas storage facility gas leak. Sempra Energy 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 Sempra Energy’s applicable insurance policies.
We identified the recoverability of the insurance receivable as a critical audit matter due to the management judgments around how the coverage provided by Sempra Energy’s 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, including the need to involve our insurance specialist.
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 our insurance specialist, we evaluated management’s judgments related to the determination of the recoverability of the insurance receivable by:
◦
Evaluating the coverage provided by Sempra Energy’s 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 Energy and the applicable insurers, and through discussions with management and with Sempra Energy’s external legal counsel.
◦
Searching external sources for and considering any contradictory evidence to Sempra Energy’s accounting assessment of probability of recoverability.
◦
Evaluating Sempra Energy’s external legal counsel’s view on the recoverability of the insurance receivable.
Shareholder Contributions to the Wildfire Fund - Refer to Note 1 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
In July 2019, California Assembly Bill (“AB”) 1054 and AB 111 (together, the “Wildfire Legislation”) were signed into State law. In accordance with the Wildfire Legislation, on September 10, 2019, Sempra Energy’s subsidiary, San Diego Gas & Electric Company (“SDG&E”) made an initial contribution to a fund established by the Wildfire Legislation (the “Wildfire Fund”) of $322.5 million and is required to make ten annual contributions of $12.9 million. These initial and annual contributions (collectively, the “Contributions”) are not subject to rate recovery.
Accounting guidance must be applied analogously, as there is no specific accounting guidance that prescribes how Sempra Energy should account for the Contributions. There are several aspects of the Wildfire Fund, such as an indeterminate life of the Wildfire Fund and the timing and likelihood that Sempra Energy will benefit from the Wildfire Fund, that make the application of accounting guidance complex.
We identified the accounting for the Contributions as a critical audit matter due to the management judgments necessary to determine that insurance accounting should be applied, and that the Contributions should be accounted for as an asset and systematically and rationally expensed over the period of benefit. Auditing management’s conclusions required judgment in evaluating the appropriate accounting treatment for the Contributions.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the accounting for the Contributions included the following, among others:
▪
We tested the effectiveness of management’s internal controls over the evaluation of the accounting treatment.
▪
With the assistance of professionals in our firm having expertise in insurance accounting, we evaluated management’s judgments related to the application of U.S. GAAP by evaluating management’s accounting analysis, Sempra Energy’s consideration of an insurance accounting model, and the potential methods of which to record the consumption of benefits related to the Contributions, to determine whether we agree with management’s accounting conclusions that the Contributions should be accounted for as an asset and systematically and rationally expensed over the estimated period of benefit.
Impact of Rate Regulation on the Financial Statements - Refer to Notes 1 and 4 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
Sempra Energy 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 Energy and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence 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 Energy’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 27, 2020
We have served as Sempra Energy’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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
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, 2019, 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 27, 2020, 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.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 27, 2020
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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
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, 2019, 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 27, 2020, 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.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 27, 2020
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 Financial Statements.
See Notes to Financial Statements.
See Notes to Financial Statements.
See Notes to Consolidated Financial Statements
SEMPRA ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA
PRINCIPLES OF CONSOLIDATION
Sempra Energy
Sempra Energy’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based energy-services holding company, and its consolidated subsidiaries and VIEs. Sempra Global is the holding company for most of our subsidiaries that are not subject to California or Texas utility regulation. Sempra Energy’s businesses were managed within six separate reportable segments until April 2019 and five separate reportable segments thereafter, which we discuss in Note 17. In the first quarter of 2019, our Sempra LNG & Midstream segment was renamed “Sempra LNG.” This segment name change had no impact on our historical position, results of operations, cash flow or segment level results previously reported. 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 Energy.
SoCalGas
SoCalGas’ common stock is wholly owned by PE, which is a wholly owned subsidiary of Sempra Energy.
In this report, we refer to SDG&E and SoCalGas collectively as the California Utilities.
BASIS OF PRESENTATION
This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.
Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:
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the Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;
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the Consolidated Financial Statements and related Notes of SDG&E and its VIE (until deconsolidation of the VIE in August 2019); and
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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
In January 2019, our board of directors approved a plan to sell our South American businesses based on our strategic focus on North America. 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. These businesses are presented as discontinued operations, as the planned sales represent a strategic shift that will have a major effect on our operations and financial results. Throughout this report, the financial information for all periods presented has been adjusted to reflect the
presentation of these businesses 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, 2019 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.
EFFECTS OF REGULATION
The California Utilities’ 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, the California Utilities record regulatory liabilities when the CPUC or 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 significant judgment by management and may include, but is not limited to, consideration of:
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the nature of the event giving rise to the assessment
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existing statutes and regulatory code
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legal precedents
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regulatory principles and analogous regulatory actions
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testimony presented in regulatory hearings
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regulatory orders
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a commission-authorized mechanism established for the accumulation of costs
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status of applications for rehearings or state court appeals
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specific approval from a commission
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historical experience
Sempra Mexico’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.
We provide information concerning regulatory assets and liabilities in Note 4.
Our Sempra Texas Utilities segment is comprised of our equity method investments in Oncor Holdings, which, at December 31, 2019, 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 annual 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 Mexico 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 nuclear decommissioning 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 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:
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quoted forward prices for commodities
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time value
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current market and contractual prices for the underlying instruments
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volatility factors
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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.
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 primarily includes:
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for SDG&E, funds held by a trustee for Otay Mesa VIE to pay certain operating costs until the deconsolidation of the VIE in August 2019; and
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for Sempra Mexico, funds primarily 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.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the Consolidated Balance Sheets to the sum of such amounts reported on the Consolidated Statements of Cash Flows.
COLLECTION ALLOWANCES
We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables. We show the changes in these allowances in the table below:
We evaluate accounts receivable collectability using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies. Adjustments to collection allowances are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends.
We write off accounts receivable in the period in which we deem the receivable to be uncollectible. We record recoveries of accounts receivable previously written off when it is known that they will be received.
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 for each of the California Utilities and, on a combined basis, for all non-CPUC regulated affiliates and overseen by their separate risk management committees.
This oversight includes calculating current and potential credit risk on a daily 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:
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prospective counterparties’ financial condition (including credit ratings)
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collateral requirements
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the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty
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downgrade triggers
We believe that we have provided adequate reserves for counterparty nonperformance.
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
The California Utilities value natural gas inventory using the LIFO method. As inventories are sold, differences between the LIFO 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. The California Utilities generally value materials and supplies at the lower of average cost or net realizable value.
Sempra Mexico and Sempra LNG value natural gas inventory and materials and supplies at the lower of average cost or net realizable value. Sempra Mexico and Sempra LNG value LNG inventory using the first-in first-out method.
The components of inventories are as follows:
WILDFIRE FUND
On July 12, 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 requires SDG&E to install at least $215 million of fire risk mitigation capital improvements, which will be the first $215 million of capital included in its wildfire mitigation plan, and recover its financing costs without a ROE.
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) 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, the primary insurance coverage is exceeded and certain other conditions are satisfied. The 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. SDG&E received its annual safety certification from the CPUC on July 26, 2019, which is valid for 12 months. Based on its 2019 rate base, the liability cap for SDG&E is approximately $900 million, which will be 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 will be transferred to California’s general fund to be used for fire risk mitigation programs.
The Wildfire Fund could initially be funded up to $10.5 billion by a loan from the State of California Surplus Money Investment Fund. Such lending will subsequently be financed through an anticipated DWR bond, 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. PG&E has agreed to participate in the Wildfire Fund, subject to bankruptcy court approval. Accordingly, if PG&E is unable to participate in the Wildfire Fund, its customers will not pay the non-bypassable charge, resulting in significantly lower Wildfire Fund contributions from ratepayers than the anticipated $10.5 billion.
The Wildfire Fund could also be funded by up to $7.5 billion in initial shareholder contributions from the IOUs (SDG&E’s share is $322.5 million, PG&E’s share is $4.8 billion and Edison’s share is $2.4 billion). The IOUs could also be required to make annual shareholder contributions to the Wildfire Fund with an aggregate value of $3 billion over a 10-year period (SDG&E’s share is $129 million, PG&E’s share is $1.9 billion and Edison’s share is $945 million). If PG&E is unable to participate in the Wildfire Fund, SDG&E’s and Edison’s aggregate shareholder contributions to the Wildfire Fund will not change and are expected to total approximately $3.8 billion. When estimating the period of benefit of the Wildfire Fund asset that we discuss below, we assume PG&E will participate in the Wildfire Fund. The contributions are not subject to rate recovery.
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 Energy. Sempra Energy funded the equity contribution to SDG&E with proceeds from settling forward sale agreements through physical delivery of shares of Sempra Energy common stock in exchange for cash, which we discuss in Note 14. Edison paid its initial shareholder contribution in September 2019.
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 California Attorney General has moved to dismiss the complaint.
Wildfire Fund Asset
SDG&E recorded a Wildfire Fund asset for its commitment to make shareholder contributions totaling $451.5 million, 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 is amortizing the Wildfire Fund asset to O&M 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, which is 15 years as of December 31, 2019, is based on several assumptions, including, but not limited to:
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historical wildfire experience of each IOU in the State of California, including frequency and severity of the wildfires
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the value of property potentially damaged by wildfires
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the effectiveness of wildfire risk mitigation efforts by each IOU
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liability cap of each IOU
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IOU prudency determination levels
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FERC jurisdictional allocation levels
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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.
We will periodically reevaluate the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in the above assumptions. SDG&E may recognize a reduction of its Wildfire Fund asset and record a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from the IOUs. The reduction to the Wildfire Fund asset may be proportionate to the Wildfire Fund’s consumption (i.e., recoveries for outstanding wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, would decrease the Wildfire Fund asset and remaining available coverage). At December 31, 2019, there were no such known claims from the IOUs requiring a reduction of the Wildfire Fund asset.
At December 31, 2019, the current portion of the Wildfire Fund asset was $29 million in Other Current Assets on Sempra Energy’s Consolidated Balance Sheet and in Prepaid Expenses on SDG&E’s Consolidated Balance Sheet, and the noncurrent portion of $392 million was in Wildfire Fund on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets.
Wildfire Fund Obligation
SDG&E recorded a Wildfire Fund obligation for its commitment to make shareholder contributions totaling $451.5 million, 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 and its first annual shareholder contribution of $12.9 million in December 2019. At December 31, 2019, SDG&E expects to make annual shareholder contributions of $12.9 million in each of the next nine years. SDG&E accretes the present value of the Wildfire Fund obligation to O&M until the liability is settled.
At December 31, 2019, the Wildfire Fund obligation was $12.9 million in Other Current Liabilities and $86 million in Deferred Credits and Other on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets.
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. ITCs from prior years are amortized to income by the California Utilities over the estimated service lives of the properties as required by the CPUC.
Under the regulatory accounting treatment required for flow-through temporary differences, the California Utilities and Sempra Mexico recognize:
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regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and
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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.
In December 2017, the TCJA was signed into law. As a result, all cumulative undistributed earnings from non-U.S. subsidiaries were deemed repatriated and subjected to a one-time U.S. federal deemed repatriation tax. To the extent we intend to repatriate cash to the U.S. from our continuing international operations, we accrue incremental income tax. 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 to the extent the related cumulative undistributed earnings 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
The California Utilities, Sempra Mexico and Sempra LNG 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 the California Utilities, 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. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Mexico and Sempra LNG record 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 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. 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 the California Utilities to provide natural gas and electric utility services, and by the Sempra Global 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 other PP&E 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, 2019, includes $484 million in electric transmission assets and $13 million in construction work in progress related to SDG&E’s 90% 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 Energy’s and SDG&E’s Consolidated Statements of Operations.
(2)
Includes capital lease assets of $1.3 billion at December 31, 2018.
(3)
Includes capital lease assets of $13 million at December 31, 2018.
(4)
Includes capital lease assets of $40 million at December 31, 2018.
(5)
Includes $178 million and $154 million at December 31, 2019 and 2018, respectively, of utility plant, primarily pipelines and other distribution assets at Ecogas.
(6)
Estimated useful lives are for land rights.
(7)
Includes capital lease assets of $136 million and associated leasehold improvements of $24 million at December 31, 2018 related to our corporate headquarters build-to-suit arrangement, which is accounted for as a ROU asset as of January 1, 2019 upon adoption of the lease standard.
Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period for the California Utilities, or the remaining term of the site leases, whichever is shortest.
(1)
Includes accumulated depreciation for capital lease assets of $48 million at December 31, 2018. Includes $263 million at December 31, 2019 related to SDG&E’s 90% interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.
(2)
Includes accumulated depreciation for capital lease assets of $37 million at December 31, 2018.
(3)
Includes accumulated depreciation for capital lease assets of $10 million and associated leasehold improvements of $3 million at December 31, 2018 related to our corporate headquarters’ build-to-suit arrangement, which is accounted for as a ROU asset as of January 1, 2019. Includes $49 million and $43 million at December 31, 2019 and 2018, respectively, of accumulated depreciation for utility plant at Ecogas.
The California Utilities finance their 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. The California Utilities 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 currently under construction by Sempra Mexico 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 interest and AFUDC.
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, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.
For our annual goodwill impairment testing, under current U.S. GAAP guidance 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 two-step, 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, changes in key personnel 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 two-step goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include:
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consideration of market transactions
▪
future cash flows
▪
the appropriate risk-adjusted discount rate
▪
country risk
▪
entity risk
Goodwill of $1,602 million at December 31, 2019 and 2018 relates to the 2016 acquisitions of IEnova Pipelines and Ventika wind power generation facilities at Sempra Mexico.
Other Intangible Assets
Other Intangible Assets included on the Sempra Energy Consolidated Balance Sheets are as follows:
Other Intangible Assets at December 31, 2019 primarily includes:
▪
a renewable energy transmission and consumption permit previously granted by the CRE that was acquired in connection with the acquisition of the Ventika wind power generation facilities; and
▪
a favorable O&M agreement acquired in connection with the acquisition of DEN, which we discuss in Note 5.
Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for intangible assets in 2019, 2018 and 2017 was $11 million, $16 million and $18 million, respectively. We estimate the amortization expense for the next five years to be $12 million per year.
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. Events or changes in circumstances that indicate that the carrying amount of a long-lived asset may not be recoverable may include:
▪
significant decreases in the market price of an asset;
▪
a significant adverse change in the extent or manner in which we use an asset or in its physical condition;
▪
a significant adverse change in legal or regulatory factors or in the business climate that could affect the value of an asset;
▪
a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continuing losses associated with the use of a long-lived asset; and
▪
a current expectation that, more-likely-than-not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
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:
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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 thereby Sempra Energy, is the primary beneficiary.
Tolling Agreements
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 we consider 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 we determine that SDG&E is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE.
SDG&E determined that none of its contracts resulted in SDG&E being the primary beneficiary of a VIE at December 31, 2019. 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 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 Energy. We provide additional information about PPAs with power plant facilities that are VIEs of which SDG&E is not the primary beneficiary in Note 16.
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. Under the terms of a related agreement, OMEC LLC could have required SDG&E to purchase the power plant (referred to as the put option) on or before October 3, 2019 for $280 million, subject to adjustments, or upon earlier termination of the PPA. SDG&E determined that it was the primary beneficiary of Otay Mesa VIE, and therefore, SDG&E and Sempra Energy consolidated Otay Mesa VIE.
In October 2018, SDG&E and OMEC LLC signed a resource adequacy capacity agreement for a term that would commence at the expiration of the current tolling agreement in October 2019 and end in August 2024. The capacity agreement was approved by OMEC LLC’s lenders and the CPUC in December 2018 and February 2019, respectively. However, given certain then pending requests for rehearing of the CPUC’s decision approving the capacity agreement, on March 28, 2019, OMEC LLC exercised the put option requiring SDG&E to purchase the power plant. On August 6, 2019, the CPUC denied the rehearing requests, and on August 23, 2019, SDG&E and OMEC LLC executed an amended resource adequacy capacity agreement that irrevocably rescinded exercise of the put option. SDG&E and Sempra Energy deconsolidated Otay Mesa VIE on August 23, 2019. No gain or loss was recognized upon deconsolidation.
Prior to deconsolidation, on August 14, 2019, OMEC LLC paid in full its variable-rate loan that was scheduled to mature in August 2024, which we describe in Note 7.
Otay Mesa VIE’s equity of $100 million at December 31, 2018 is included on the Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.
The following table summarizes the deconsolidation:
Sempra Texas Utilities
On March 9, 2018, we completed the acquisition of an indirect, 100% interest in Oncor Holdings, a VIE that, at December 31, 2019, owns an 80.25% interest in Oncor. Sempra Energy is not the primary beneficiary of the 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 Notes 5 and 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 $11,519 million at December 31, 2019 and $9,652 million at December 31, 2018.
Sempra Mexico
Sempra Mexico’s businesses also enter into arrangements that could include variable interests. We evaluate these arrangements
and applicable entities based on the qualitative and quantitative analyses described above. Certain of these entities are service or project companies that are VIEs because the total equity at risk is not sufficient for the entities to finance their activities without additional subordinated financial support. As the primary beneficiary of these companies, we consolidate them. The assets of these VIEs totaled approximately $126 million at December 31, 2019 and $286 million at December 31, 2018 and consisted primarily of PP&E and other long-term assets. Our maximum exposure to loss is equal to the carrying value of these assets.
Sempra Renewables
Certain of Sempra Renewables’ wind and solar power generation projects were held by limited liability companies whose members were Sempra Renewables and financial institutions. The financial institutions were noncontrolling tax equity investors to which earnings, tax attributes and cash flows were allocated in accordance with the respective limited liability company agreements. These entities were VIEs and Sempra Energy was the primary beneficiary, generally due to Sempra Energy’s power as the operator of the renewable energy projects to direct the activities that most significantly impacted the economic performance of these VIEs. As the primary beneficiary of these tax equity limited liability companies, we consolidated them. We sold the solar entities in December 2018 and summarize the impact of the deconsolidation of these solar and other Sempra Renewables entities in Note 5. We sold the wind entities in April 2019. At December 31, 2018, Sempra Energy’s Consolidated Balance Sheet includes $301 million in Assets Held for Sale, $9 million in Liabilities Held for Sale, and equity of $158 million in Other Noncontrolling Interests associated with these wind entities.
Sempra LNG
Cameron LNG JV is a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary of the VIE because we do not have the power to direct the most significant activities of Cameron LNG JV, and 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 $1,256 million at December 31, 2019 and $1,271 million at December 31, 2018. Our maximum exposure to loss, which fluctuates over time, includes the carrying value of our investment and guarantees that we discuss in Note 6.
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 over the life of the related asset by depreciating the asset retirement cost (measured as the present value of the obligation at the time the asset is placed into service), and accreting the obligation until the liability is settled. Our rate-regulated entities, including the California Utilities, 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
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fuel and storage tanks
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natural gas transmission and distribution systems
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hazardous waste storage facilities
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asbestos-containing construction materials
SDG&E
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nuclear power facilities
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electric transmission and distribution systems
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energy storage systems
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power generation plants
SoCalGas
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underground natural gas storage facilities and wells
All Other Sempra Energy Businesses
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natural gas transportation and distribution systems
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power generation plants
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LNG facility
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LPG terminal
The changes in ARO are as follows:
(1)
Current portion of the ARO for Sempra Energy Consolidated is included in Other Current Liabilities on the Consolidated Balance Sheets.
(2)
In 2018, we reclassified $6 million at Sempra Renewables and $8 million at Sempra LNG to liabilities held for sale, and $5 million related to TdM from liabilities held for sale, and deconsolidated $52 million at Sempra Renewables, as we discuss in Note 5. Liabilities held for sale are included in Other Current Liabilities on the Sempra Energy Consolidated Balance Sheets.
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:
▪
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 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:
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foreign currency translation adjustments
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certain hedging activities
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changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans
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unrealized gains or losses on available-for-sale securities
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.
(3)
Pension and Other Postretirement Benefits and Total AOCI include a $4 million transfer of liabilities from SoCalGas to Sempra Energy related to the nonqualified pension plan.
(1)
Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
(2)
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 Energy as NCI. Sempra Energy records charges against income related to NCI for preferred stock dividends declared by SoCalGas. We provide additional information regarding SoCalGas’ preferred stock in Note 13.
Other Noncontrolling Interests
SDG&E
As we discuss in “Variable Interest Entities” above, in August 2019, SDG&E and Sempra Energy deconsolidated Otay Mesa VIE after SDG&E determined that it is no longer the primary beneficiary of the VIE.
Sempra Mexico
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 Energy’s ownership interest in IEnova from 66.5% to 66.6%.
In 2018, IEnova repurchased 2,000,000 shares of its outstanding common stock held by NCI for approximately $7 million, resulting in an increase in Sempra Energy’s ownership interest in IEnova from 66.4% to 66.5%.
Sempra Renewables
In April 2019, Sempra Renewables sold its remaining wind assets and investments, which included its wind tax equity arrangements. The remaining interest in PXiSE Energy Solutions, LLC was subsumed into Parent and other.
Sempra LNG
Sempra LNG and IEnova are developing a proposed natural gas liquefaction project at the site of IEnova’s existing ECA LNG Regasification terminal. Sempra LNG consolidates the ECA LNG JV proposed liquefaction project. Thus, Sempra Energy’s NCI in IEnova’s 50% interest in the proposed project is reported at Sempra LNG.
In February 2019, Sempra LNG purchased for $20 million the 9.1% minority interest in Bay Gas immediately prior to the sale of 100% of Bay Gas, which we discuss in Note 5.
The following table provides information about noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Consolidated Balance Sheets:
(1)
IEnova and Chilquinta Energía have subsidiaries with NCI held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.
(2)
Net income or loss attributable to NCI is computed using the HLBV method and is not based on ownership percentages.
(3)
In April 2019, PXiSE Energy Solutions, LLC was subsumed into Parent and other.
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, litigation expense and rent.
FOREIGN CURRENCY TRANSLATION AND TRANSACTIONS
The majority of our operations in South America as well as our natural gas distribution utility in Mexico, Ecogas, 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 the Sempra Energy Consolidated Statements of Cash Flows.
Currency transaction gains (losses) in a currency other than Sempra Mexico’s functional currency were $21 million, $(6) million and $(33) million for the years ended December 31, 2019, 2018 and 2017, respectively, and are included in Other Income, Net, on
the Sempra Energy Consolidated Statements of Operations. Currency transaction gains (losses) in a currency other than Sempra South American Utilities’ functional currency are included in discontinued operations.
TRANSACTIONS WITH AFFILIATES
We summarize amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas in the following table.
(1)
Amounts include principal balances plus accumulated interest outstanding.
(2)
Mexican peso-denominated revolving line of credit for up to 14.2 billion Mexican pesos or approximately $751 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus 220 bps (9.65% at December 31, 2019), to finance construction of the natural gas marine pipeline.
(3)
U.S. dollar-denominated loan at a variable interest rate based on the 30-day LIBOR plus 637.5 bps (8.89% at December 31, 2018).
(4)
U.S. dollar-denominated loan at a variable interest rate based on 6-month LIBOR plus 290 bps (4.81% at December 31, 2019).
(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 Energy 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 revenues and cost of sales from unconsolidated affiliates.
California Utilities
Sempra Energy, 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 Energy 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 Energy 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 Energía Sierra Juárez wind power generation facility. Energía Sierra Juárez is a 50% owned and unconsolidated JV of Sempra Mexico.
Sempra Mexico
Sempra Mexico, through its 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 LNG
Sempra LNG provides project administration and operating and maintenance services to Cameron LNG JV, and also provides personnel under an administrative services arrangement. Sempra LNG has an agreement to provide transportation services to Cameron LNG JV for capacity on the Cameron Interstate Pipeline. Sempra Energy has provided guarantees to its Cameron LNG JV, as we discuss in Note 6.
RESTRICTED NET ASSETS
Sempra Energy Consolidated
As we discuss below, the California Utilities and certain other Sempra Energy subsidiaries have restrictions on the amount of funds that can be transferred to Sempra Energy by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally, certain other Sempra Energy 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 Energy. At December 31, 2019, Sempra Energy was in compliance with all covenants related to its debt agreements.
At December 31, 2019, the amount of restricted net assets of consolidated entities of Sempra Energy, including the California Utilities discussed below, that may not be distributed to Sempra Energy in the form of a loan or dividend is $10.4 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $21.5 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries can provide to Sempra Energy, 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, $634 million of Sempra Energy’s consolidated retained earnings represents undistributed earnings of equity method investments at December 31, 2019.
California Utilities
The CPUC’s regulation of the California Utilities’ capital structures limits the amounts available for dividends and loans to Sempra Energy. At December 31, 2019, Sempra Energy could have received combined loans and dividends of approximately $885 million from SDG&E and approximately $742 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 Energy 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, 2019 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, 2019, SDG&E’s restricted net assets were $6.2 billion and SoCalGas’ restricted net assets were $4.0 billion, which could not be transferred to Sempra Energy.
Sempra Texas Utilities
Sempra Texas Utilities owns an indirect, 100% interest in Oncor Holdings, which, at December 31, 2019, 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 Energy include:
▪
In connection with the ring-fencing measures, governance mechanisms and commitments that we describe in Note 6, 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 the 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 (57.5% debt to 42.5% equity as of December 31, 2019).
▪
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, 2019, all of Oncor’s senior secured ratings were above BBB.
▪
Oncor’s revolving credit line, note purchase agreements, and term loan credit 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, 2019, Oncor was in compliance with these covenants.
Based on these restrictions, at December 31, 2019, Oncor’s restricted net assets were $10.9 billion, which could not be transferred to Sempra Energy.
As we discuss in Note 5, we acquired an indirect, 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities, in May 2019. 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.
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Sharyland Utilities must remain in compliance with the 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 its debt-to-equity ratio to exceed 55% debt to 45% equity, which was authorized by the PUCT.
▪
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, 2019, Sharyland Utilities was in compliance with these and all other covenants.
Based on these restrictions, at December 31, 2019, Sharyland Utilities’ restricted net assets were $115 million, which could not be transferred to its owners.
Sempra Mexico
Significant restrictions at Sempra Mexico include:
▪
Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $178 million at Sempra Energy’s consolidated Mexican subsidiaries at December 31, 2019.
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Wholly owned IEnova Pipelines has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under this restriction, net assets totaling $17 million are restricted at December 31, 2019.
▪
Wholly owned Ventika has long-term debt agreements that require it to maintain reserve accounts to pay the projects’ debt. The debt agreements may limit the project companies’ ability to incur liens, incur additional indebtedness, make investments, pay cash dividends and undertake certain additional actions. Under these restrictions, net assets totaling $14 million are restricted at December 31, 2019.
▪
Energía Sierra Juárez, a 50% owned and unconsolidated JV of Sempra Mexico, has long-term debt agreements that require the establishment and funding of project and reserve accounts to which the proceeds of loans, letter of credit borrowings, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The long-term debt agreements also limit the JV’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions. Under these restrictions, net assets totaling $15 million are restricted at December 31, 2019.
▪
TAG JV, a 50% owned and unconsolidated JV of Sempra Mexico, 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 $171 million are restricted at December 31, 2019.
Sempra LNG
Sempra LNG 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. 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 have been pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors. We discuss Cameron LNG JV’s debt agreements and the associated Sempra Energy guarantees in Note 6. Under these restrictions, total assets of Cameron LNG JV of approximately $10.3 billion are restricted at December 31, 2019.
OTHER INCOME, NET
Other Income, Net on the Consolidated Statements of Operations consists of the following:
(1)
Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans, recorded in O&M on the Consolidated Statements of Operations.
(2)
Includes gains of $30 million in 2019 and losses of $3 million and $35 million in 2018 and 2017, respectively, 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 financial condition, results of operations, cash flows or disclosures.
ASU 2016-02, “Leases,” ASU 2018-01, “Land Easement Practical Expedient for Transition to Topic 842,” ASU 2018-10, “Codification Improvements to Topic 842, Leases,” ASU 2018-11, “Leases (Topic 842): Targeted Improvements,” ASU 2018-20, “Narrow-Scope Improvements for Lessors” and ASU 2019-01, “Leases (Topic 842): Codification Improvements” (collectively referred to as the “lease standard”): In 2016, the Financial Accounting Standards Board began issuing the first in a series of ASUs intended to increase transparency and comparability among organizations with leasing activities. The most significant provision of the lease standard is the requirement that lessees recognize operating lease ROU assets and lease liabilities on the balance sheet.
We adopted the lease standard on January 1, 2019 using the optional modified retrospective transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We elected the package of practical expedients that permits us to not reassess (a) whether a contract is or contains a lease, (b) lease classification or (c) determination of initial direct costs, which allows us to carry forward accounting conclusions under previous U.S. GAAP on contracts that commenced prior to adoption of the lease standard. We also elected the land easement practical expedient, which allows us to continue to account for pre-existing land easements under our accounting policy that existed before adoption of the lease standard. We did not elect the practical expedient to use hindsight in making judgments when determining the lease term.
The adoption of the lease standard did not change our previously reported financial statements. However, in accordance with the lease standard, on a prospective basis, a significant portion of finance lease costs for PPAs that have historically been presented in
Cost of Electric Fuel and Purchased Power are now presented in Depreciation and Amortization Expense and Interest Expense on Sempra Energy’s and SDG&E’s statements of operations. Additionally, the adoption of the lease standard had a material impact on our balance sheets at January 1, 2019 due to the initial recognition of ROU assets and lease liabilities for operating leases. Our finance leases were already included on our balance sheets prior to adoption of the lease standard, consistent with previous U.S. GAAP for capital leases.
The following table shows the initial increases (decreases) on our balance sheets at January 1, 2019 from adoption of the lease standard.
As a result of the adoption of the lease standard, we derecognized the asset and liability associated with our corporate headquarters building in accordance with the transition provisions for build-to-suit arrangements. On a prospective basis, we will account for the corporate headquarters building lease as an operating lease. The initial impact is included in the above table.
We include additional disclosures about our leases in Note 16.
ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13, as amended by subsequently issued ASUs, changes how entities will measure credit losses for most financial assets and certain other instruments. The standard introduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for estimating the credit losses.
For public entities, ASU 2016-13 is effective for fiscal years beginning after December 15, 2019, including interim periods therein, with early adoption permitted for fiscal years beginning after December 15, 2018. The amendments are to be applied using a modified retrospective approach through a cumulative-effect adjustment to retained earnings at the beginning of the first reporting period in the year of adoption.
On a prospective basis, the new standard will primarily apply to our accounts receivable balances, amounts due from unconsolidated affiliates and off-balance sheet financial guarantees. We will adopt the standard on January 1, 2020.
We expect no impact to SDG&E’s or SoCalGas’ balance sheets from adoption. The following table shows the expected (decreases) increases on Sempra Energy’s balance sheet at January 1, 2020 from adoption of ASU 2016-13.
ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and 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. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments are to be applied on a prospective basis. We will adopt the standard on January 1, 2020.
ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: ASU 2018-02 contains amendments that allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the TCJA. Under ASU 2018-02, an entity is required to provide certain disclosures regarding stranded tax effects, including its accounting policy related to releasing the income tax effects from AOCI. The amendments in this update can be applied either as of the beginning of the period of adoption or retrospectively as of the date of enactment of the TCJA and to each period in which the effect of the TCJA is recognized. We adopted ASU 2018-02 on January 1, 2019 and reclassified the income tax effects of the TCJA from AOCI to retained earnings.
The impact from adoption of ASU 2018-02 on January 1, 2019 was as follows:
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Sempra Energy: increase of $40 million to beginning Retained Earnings, $2 million to noncurrent Regulatory Liabilities and $42 million to Accumulated Other Comprehensive Loss;
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SDG&E: increase of $2 million to beginning Retained Earnings and Accumulated Other Comprehensive Loss; and
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SoCalGas: increase of $2 million to beginning Retained Earnings, $2 million to noncurrent Regulatory Liabilities and $4 million to Accumulated Other Comprehensive Loss.
ASU 2019-12, “Simplifying the Accounting for Income Taxes”: ASU 2019-12 simplifies certain areas of accounting for income taxes. In addition to other changes, this standard amends ASC 740, “Income Taxes,” as follows:
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removes the exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, including discontinued operations or other comprehensive income;
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simplifies the recognition of deferred taxes related to basis differences as a result of ownership changes in investments;
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specifies an entity is not required to allocate the consolidated amount of current and deferred tax expense to a legal entity that is not subject to tax in its separate financial statements; and
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requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual ETR computation in the interim period that includes the enactment date.
For public entities, ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim periods therein, with early adoption permitted. The transition method related to the amendments made by ASU 2019-12 vary based on the nature of the change. We are currently evaluating our planned adoption date and the effect of the standard on our ongoing financial reporting.
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 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, the California Utilities pay franchise fees to operate in various municipalities. The California Utilities bill these franchise fees to their customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of the California Utilities’ 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:
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SDG&E
▪
SoCalGas
▪
Sempra Mexico’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.
The California Utilities and Ecogas recognize revenues based on regulator-approved revenue requirements, which allows the utilities to recover their reasonable operating costs and provides the opportunity to realize their authorized rates of return on their investments. While the California Utilities’ revenues are not affected by actual sales volumes, the pattern of their revenue recognition during the year is affected by seasonality. SoCalGas recognizes annual authorized revenue for core natural gas customers using seasonal factors established in the Triennial Cost Allocation Proceeding. Accordingly, a significant portion of SoCalGas’ annual earnings are recognized in the first and fourth quarters of each year. SDG&E’s authorized revenue recognition is also impacted by seasonal factors, resulting in higher earnings in the third quarter when electric loads are typically higher than in the other three quarters of the year.
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.
The California Utilities 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 the California Utilities 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. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts.
Energy-Related Businesses Revenues
Midstream Revenues
Midstream revenues at Sempra Mexico and Sempra LNG 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.
Sempra Mexico’s marketing operations sell natural gas to the CFE and other customers under supply agreements. Sempra Mexico 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.
Through its marketing operations, Sempra LNG has contracts to sell natural gas and LNG to Sempra Mexico that allow Sempra Mexico to satisfy its obligations under supply agreements with the CFE and other customers, and to supply Sempra Mexico’s TdM power plant. Because Sempra Mexico either immediately delivers the natural gas to its customers or consumes the benefits simultaneously (by using the gas to supply TdM), revenues from Sempra LNG’s sale of natural gas to Sempra Mexico are generally recognized over time as delivered. Revenues from LNG sales are recognized at the point when the cargo is delivered to Sempra Mexico.
Revenues from the sale of LNG and natural gas by Sempra LNG to Sempra Mexico are adjusted for indemnity payments and profit sharing. We consider these adjustments to be forms of variable consideration that are associated with the sale of LNG and natural gas to Sempra Mexico, and therefore, Sempra LNG records the related costs as an offset to revenues, with no impact to Sempra Energy’s consolidated revenues.
We recognize storage revenue from firm capacity reservation agreements, under which we collect a fee for reserving storage capacity for customers in our underground 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, on February 7, 2019, Sempra LNG 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.
Renewables Revenues
Sempra Renewables and Sempra Mexico 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 Mexico, 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. We invoice customers based on the volume of energy delivered at rates pursuant to the PPAs. As we discuss in Note 5, in December 2018, we completed the sale of Sempra Renewables’ U.S. operating solar assets, solar and battery storage development projects and its 50% ownership interest in a wind power generation facility. In April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments.
Sempra LNG continues to have a contractual agreement to provide scheduling and marketing of renewable power for Sempra Mexico’s renewables’ entities. Invoiced amounts are based on a fixed fee per MWh scheduled.
Other Revenues from Contracts with Customers
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.
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, 2019, we expect to recognize revenue related to the fixed fee component of the consideration as shown below. Sempra Energy’s remaining performance obligations primarily relate to capacity agreements for natural gas storage and transportation at Sempra Mexico. SoCalGas did not have any remaining performance obligations at December 31, 2019.
(1)
Excludes intercompany transactions.
Contract Balances 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 Energy’s and SDG&E’s contract liabilities are presented below. There were no contract liability activities at SDG&E in 2018 or SoCalGas in 2019 or 2018.
(1)
Includes $4 million and $4 million in Other Current Liabilities and $159 million and $87 million in Deferred Credits and Other on the Sempra Energy and SDG&E Consolidated Balance Sheets, respectively.
Receivables from Revenues from Contracts with Customers
The table below shows receivable balances associated with revenues from contracts with customers on our Consolidated Balance Sheets.
(1)
Amount is presented net of amounts due to unconsolidated affiliates on the Consolidated Balance Sheets, when right of offset exists.
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 the California Utilities 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 the California Utilities to use a “decoupling” mechanism, which allows the California Utilities 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 the California Utilities 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 the California Utilities to collect revenue requirements for operating costs and capital related costs (such as depreciation, taxes and return on rate base) from customers, including:
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costs to purchase natural gas and electricity;
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costs associated with administering public purpose, demand response, and customer energy efficiency programs;
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other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and
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costs associated with third party liability insurance premiums.
Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded within a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met at the time the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund for programs authorized, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers.
We discuss balancing accounts and their effects further in Note 4.
Other Revenues
Sempra LNG has an agreement to supply LNG to Sempra Mexico’s ECA LNG Regasification terminal. Although the LNG sale and purchase agreement specifies a number of cargoes to be delivered annually, actual cargoes delivered by the supplier have traditionally been significantly lower than the maximum specified under the agreement. As a result, Sempra LNG is contractually required to make monthly indemnity payments to Sempra Mexico for failure to deliver the contracted LNG.
Sempra Mexico generates lease revenues from operating lease agreements with PEMEX and CENAGAS for the use of natural gas and ethane pipelines and LPG storage facilities. Certain PPAs at Sempra Renewables were also accounted for as operating leases prior to sale of its solar and wind assets in December 2018 and April 2019.
Sempra LNG also recognizes other revenues from:
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fees related to contractual counterparty obligations for non-delivery of LNG cargoes, as described above; and
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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 the 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.
(1)
At December 31, 2019 and 2018, the noncurrent portion of regulatory balancing accounts - net undercollected for SDG&E was $108 million and $78 million, respectively. At December 31, 2019 and 2018, the noncurrent portion of regulatory balancing accounts - net undercollected for SoCalGas was $500 million and $185 million, respectively.
(2)
Includes regulatory assets earning a return.
In the table above:
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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.
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Deferred income taxes refundable/recoverable in rates are based on current regulatory ratemaking and income tax laws.
SDG&E, SoCalGas and Sempra Mexico expect to refund/recover net regulatory liabilities/assets related to deferred income taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities include certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 8.
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Regulatory assets/liabilities related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded.
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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.
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Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).
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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.
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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 50-year period.
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Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, including commodity costs. Depreciation 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.
Amortization expense on regulatory assets for the years ended December 31, 2019, 2018 and 2017 was $7 million, $5 million and $50 million, respectively, at Sempra Energy Consolidated, $3 million, $2 million and $49 million, respectively, at SDG&E, and $4 million, $3 million and $1 million, respectively, at SoCalGas.
CALIFORNIA UTILITIES
CPUC General Rate Case
The CPUC uses GRC proceedings to set rates designed to allow the California Utilities to recover their reasonable operating costs and to provide the opportunity to realize their authorized rates of return on their investments.
2019 General Rate Case
On September 26, 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. This is the first GRC that includes revenues authorized for risk assessment mitigation phase activities.
The 2019 GRC FD adopts 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), which is $213 million lower than the $2,203 million that SDG&E had requested in its updated application. SDG&E’s adopted 2019 revenue requirement represents an increase of $107 million (5.70%) over its authorized 2018 revenue requirement.
The 2019 GRC FD adopts a test year 2019 revenue requirement of $2,770 million for SoCalGas, which is $167 million lower than the $2,937 million that SoCalGas had requested in its updated application. SoCalGas’ adopted 2019 revenue requirement represents an increase of $314 million (12.80%) over its authorized 2018 revenue requirement.
The increases include separately authorized components for O&M and capital-related costs, as follows:
The adopted revenue requirements associated with the period from January 1, 2019 through December 31, 2019 are being recovered in rates over a 24-month period beginning in January 2020. At December 31, 2019, SDG&E recorded an associated regulatory asset of $111 million, with $56 million as noncurrent, and SoCalGas recorded an associated regulatory asset of $400 million, with $200 million as noncurrent.
In January 2020, the CPUC issued a final decision implementing a four-year GRC cycle for California IOUs. The California Utilities 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).
The 2019 GRC FD approves for the California Utilities the 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 the California Utilities to seek recovery of additional liability insurance coverage.
Pursuant to the 2016 GRC FD, SDG&E and SoCalGas each established a two-way income tax expense memorandum account to track, among other items, certain revenue variances resulting from certain differences between the income tax expense forecasted in the GRC and the income tax expense incurred from 2016 through 2018. SDG&E and SoCalGas recorded regulatory liabilities associated with the 2016 through 2018 tracked forecasting differences of $86 million and $89 million, respectively. The 2019 GRC FD clarifies that forecasting differences, which we previously included in this tracked activity, are not subject to tracking in the income tax expense memorandum account. Final resolution of the scope of the two-way income tax expense memorandum account for the 2016 through 2018 period is pending at the CPUC and could impact the disposition of these regulatory liabilities. We expect resolution in the first half of 2020.
The 2016 GRC FD revenue requirement was authorized using a federal income tax rate of 35%. As a result of the TCJA, the federal income tax rate became 21% effective January 1, 2018. Since SDG&E and SoCalGas continued to collect authorized revenues based on a 35% tax rate, SDG&E and SoCalGas recorded regulatory liabilities of $88 million and $75 million, respectively. Pursuant to the 2019 GRC FD, SDG&E and SoCalGas are refunding the regulatory balances over a 24-month period starting in January 2020. SDG&E also recorded a $66 million regulatory liability at December 31, 2019, relating to its FERC jurisdictional rates, which it began refunding in June 2019.
CPUC Cost of Capital
In April 2019, SDG&E and SoCalGas filed separate applications with the CPUC to update their cost of capital effective January 1, 2020. SDG&E proposed to adjust its authorized capital structure by increasing the amount of its common equity from 52% to 56%. SDG&E also proposed to increase its authorized ROE from 10.2% to 14.3% (with the aggregate ROE proposal including a quantified premium for wildfire liability risk), and to increase its authorized return on rate base from 7.55% to 10.03%. In August 2019, SDG&E filed supplemental testimony to update its ROE request from 10.2% to 12.38% to reflect the impacts of the Wildfire Legislation, including a revised premium for wildfire liability risk, and its authorized return on rate base from 7.55% to 8.95%. SoCalGas proposed to adjust its authorized capital structure by increasing the amount of its common equity from 52% to 56%, its authorized ROE from 10.05% to 10.7% and its authorized return on rate base from 7.34% to 7.85%.
In December 2019, the CPUC approved the cost of capital and rate structures (shown in the table below) for SDG&E and SoCalGas that are effective January 1, 2020 and will remain in effect through December 31, 2022. SDG&E did not propose a 2020 cost of preferred equity in this proceeding. In January 2020, SDG&E filed an advice letter to continue the cost of preferred equity for test year 2020 at 6.22%, which is pending CPUC approval.
The CCM was reauthorized in the 2020 cost of capital proceeding to continue through 2022. The CCM benchmark rate for the 2020 cost of capital is the average monthly utility bond index, as published by Moody’s, for the 12-month period from October 2018 through September 2019. SDG&E’s CCM benchmark rate is 4.491%, based on Moody’s Baa- utility bond index, and SoCalGas’ CCM benchmark rate is 4.024%, based on Moody’s A- utility bond index. The index applicable to each utility is based on each utility’s credit rating.
The CCM benchmark rates for SDG&E and SoCalGas are the basis of comparison to determine if future measurement periods “trigger” the CCM. The 12 months ending September 2020 shall be the first “CCM Period” to determine if there has been a trigger at SDG&E or SoCalGas. The trigger occurs if the change in the applicable average Moody’s utility bond index relative to the CCM benchmark is larger than plus or minus 1.000%. Accordingly, if a change of more than plus or minus 1.000% occurs, SDG&E’s, SoCalGas’, or both utilities’ authorized ROE would be adjusted, upward or downward, by one half of the difference between the CCM benchmark and the 12-month average determined during the CCM Period. In addition, the authorized recovery rate for the respective utilities’ cost of debt and preferred stock would be adjusted to their respective actual weighted-average cost, with no change to the authorized capital structure. In the event of a CCM trigger, the CCM benchmark is also reestablished. These adjustments would become effective in authorized rates on January 1 of the year following the CCM trigger.
SDG&E
FERC Rate Matters and Cost of Capital
SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets.
SDG&E’s current estimated FERC return on rate base under the TO4 formula rate request filing is 7.51% based on its capital structure as follows:
FERC Formulaic Rate Filing
In October 2018, SDG&E submitted its TO5 filing to the FERC proposing, among other items, an increase to SDG&E’s current authorized FERC ROE from 10.05% to 11.20%. This proceeding establishes the transmission revenue requirement, including rate of return, for SDG&E’s FERC-regulated electric transmission operations and assets. On December 31, 2018, the FERC issued its order accepting and suspending SDG&E’s TO5 filing for five months, during which the existing TO4 rates remained in effect, and established hearing and settlement procedures. The suspension period ended on June 1, 2019, when the proposed TO5 rates took effect, subject to refund and the outcome of the rate filing. As a result, until a new ROE is authorized, the current ROE of 10.05% is the basis of SDG&E’s FERC-related revenue recognition.
In October 2019, SDG&E and all settling parties reached an agreement on all issues set for hearing in the proceeding. The agreement provides 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. SDG&E will refund the California ISO additional 50 bps of ROE as of the refund effective date (June 1, 2019) in this proceeding if the FERC issues an order ruling that California IOUs are no longer eligible for the additional California ISO
ROE. The agreement also includes the collection of additional FERC revenues of $17 million to conclude a rate base matter, net of certain refunds to be paid to CPUC-jurisdictional customers. We expect a FERC order on the settlement terms in the first half of 2020.
When we receive a final decision, SDG&E expects to record the cumulative earnings effect of retroactive application to June 1, 2019 for any difference between the current ROE and the approved ROE.
SOCALGAS
Billing Practices OII
In May 2017, the CPUC issued an OII to determine whether SoCalGas violated any provisions of the California Public Utilities Code, General Orders, CPUC decisions, or other requirements pertaining to billing practices from 2014 through 2016. The CPUC examined the timeliness of monthly bills, extending the billing period for customers, and issuing estimated bills, including an examination of SoCalGas’ gas tariff rules. In January 2019, the CPUC ordered SoCalGas to pay $8 million in penalties, including $3 million that was paid in July 2019 to California’s general fund and $5 million to be credited to customers that received delayed bills (greater than 45 days) in the form of a $100 bill credit. SoCalGas filed an appeal of the CPUC’s conclusions in the order, which, in April 2019, the CPUC denied. SoCalGas filed a rehearing request in May 2019, which is pending before the CPUC. The CPUC granted SoCalGas’ request to delay distribution of the $100 bill credit to customers until a final decision on the rehearing.
SEMPRA MEXICO
In July and December of 2018, the CRE adjusted Ecogas’ natural gas distribution rates charged to end-users in 2014 through 2016. Ecogas recorded regulatory assets of $7 million and $5 million, respectively, for these tariff adjustments, which are recoverable in rates effective September 1, 2018 and February 1, 2019, respectively, through December 31, 2020.
NOTE 5. ACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS
We consolidate assets acquired and liabilities assumed as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.
ACQUISITIONS
Sempra Texas Utilities
TTHC
In February 2020, Sempra Texas Intermediate Holding Company LLC, acquired an additional indirect 0.2% interest in Oncor through its acquisition of a 1% interest in TTHC from Hunt Strategic Utility Investment, L.L.C., including notes receivable due from TTHC with an aggregate outstanding balance of approximately $5.5 million, for a total purchase price of approximately $23 million in cash, bringing Sempra Energy’s indirect ownership in Oncor to approximately 80.45%. TTHC owns 100% of TTI, which owns 19.75% of Oncor’s outstanding membership interests.
Oncor Holdings
In March 2018, Sempra Energy completed the acquisition of an indirect, 100% interest in Oncor Holdings, which owned 80.03% of Oncor, and other EFH assets and liabilities unrelated to Oncor, pursuant to the Merger Agreement with EFH. Under the Merger Agreement, we paid Merger Consideration of $9.45 billion in cash and an additional $31 million representing an adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings. Also in March 2018, in a separate transaction, Sempra Energy, through its interest in Oncor Holdings, acquired an additional 0.22% of the outstanding membership interests in Oncor from OMI for $26 million in cash, bringing Sempra Energy’s indirect ownership in Oncor to 80.25%. TTI continues to own 19.75% of Oncor’s outstanding membership interest.
Pursuant to the Merger Agreement, the reorganized EFH (renamed Sempra Texas Holdings Corp.) merged with an indirect subsidiary of Sempra Energy, with Sempra Texas Holdings Corp. continuing as the surviving company and an indirect, wholly
owned subsidiary of Sempra Energy. Sempra Texas Holdings Corp. wholly owns EFIH (renamed Sempra Texas Intermediate Holding Company LLC), which holds our 100% interest in Oncor Holdings. Other assets and liabilities unrelated to Oncor that were acquired with Sempra Texas Holdings Corp. have been subsumed into our parent organization, Parent and other.
Due to ring-fencing measures, existing governance mechanisms and commitments in effect, we do not have the power to direct the significant activities of Oncor Holdings and Oncor. Consequently, we account for our 100% ownership interest in Oncor Holdings as an equity method investment. See Note 6 for additional information about our equity method investment in Oncor Holdings and related ring-fencing measures.
In anticipation of the Merger, in January 2018, we completed registered public offerings of our common stock (including shares offered pursuant to forward sale agreements), series A preferred stock and long-term debt, as we discuss in Notes 7, 13 and 14. These offerings provided total initial net proceeds of approximately $7.0 billion for partial funding of the Merger Consideration, of which approximately $800 million was used to pay down commercial paper, pending the closing of the Merger.
In March 2018, to fund a portion of the Merger Consideration, we settled approximately $900 million (net of underwriting discounts of $16 million) of forward sales under the forward sale agreements entered into in connection with the public offering of common stock in January 2018 by delivery of 8,556,630 shares of newly issued Sempra Energy common stock, as we discuss in Note 14. We raised the remaining portion of the Merger Consideration through issuances of approximately $2.6 billion in commercial paper with a weighted-average maturity of 47 days and a weighted-average interest rate of 2.2% per annum.
The total purchase price paid was comprised of the following:
•
$9,450 million of Merger Consideration;
•
$31 million adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings;
•
$26 million paid in a separate transaction to acquire an additional 0.22% of the outstanding membership interests in Oncor from OMI; and
•
$59 million of transaction costs included in the basis of our investment in Oncor Holdings.
We accounted for the Merger as an asset acquisition, as the equity method investment in Oncor Holdings represents substantially all of the fair value of the gross assets acquired. The following table sets forth the allocation of the total purchase price paid to the identifiable assets acquired and liabilities assumed.
(1)
In the fourth quarter of 2018, we received additional information regarding deferred income taxes related to the resolution of claims in EFH’s emergence from bankruptcy as of the acquisition date. As a result, we recorded an adjustment to increase our investment in Oncor Holdings by $64 million, decrease deferred income tax assets by $66 million and decrease deferred credits and other liabilities by $2 million. Also in the fourth quarter of 2018, we recorded $2 million of additional purchase price paid related to additional transaction costs.
The fair value of the equity method investment in Oncor Holdings is primarily attributable to Oncor’s business. Therefore, we considered the underlying assets and liabilities of Oncor when determining the fair value of our equity method investment. As a regulated entity, Oncor’s rates are set and approved by the PUCT, and are designed to recover the cost of providing service and the opportunity to earn a reasonable return on its investments. Accordingly, Oncor applies the guidance under the provisions of U.S. GAAP governing rate-regulated operations. Under U.S. GAAP, regulation is viewed as being a characteristic (restriction) of
a regulated entity’s assets and liabilities, and the impact of regulation is considered a fundamental input to measuring the fair value of Oncor’s assets and liabilities. Under this premise, we concluded that the carrying values of all assets and liabilities recoverable through rates are representative of their fair values.
In May 2019, Oncor completed the acquisition of 100% of the issued and outstanding shares of InfraREIT and 100% of the limited partnership units of its subsidiary, InfraREIT Partners, LP, pursuant to the InfraREIT Merger Agreement. Under the InfraREIT Merger Agreement, Oncor paid merger consideration of $1,275 million, or $21 per share, plus certain transaction costs incurred by InfraREIT and its subsidiaries and paid by Oncor on their behalf, including $40 million for a management agreement termination fee. In connection with and immediately after the closing, Oncor also extinguished all of InfraREIT’s outstanding debt (totaling $953 million) by repaying an aggregate principal amount of $602 million on behalf of InfraREIT’s subsidiaries (using proceeds from a term loan and issuances of commercial paper), and exchanging an aggregate principal amount of $351 million of secured senior notes issued by InfraREIT subsidiaries for secured senior notes issued by Oncor. Oncor received a total of $1,330 million in capital contributions from Sempra Energy and certain indirect equity holders of TTI, proportionate to their respective ownership interest in Oncor, to fund the purchase price and certain expenses.
As part of Oncor’s acquisition of interests in InfraREIT, immediately prior to closing the InfraREIT Merger Agreement, SDTS accepted and assumed certain assets and liabilities of Sharyland Utilities, LP in exchange for certain SDTS assets, pursuant to the Asset Exchange Agreement. SDTS received real property and other assets used in the electric transmission and distribution business in Central, North and West Texas, as well as the equity interests in GS Project Entity, LLC (a wholly owned subsidiary of Sharyland Utilities, LP), and Sharyland Utilities, LP received real property and other assets used in the electric transmission and distribution business near the Texas-Mexico border. Pursuant to the Asset Exchange Agreement, immediately prior to the completion of the exchange, SDTS became a wholly owned, indirect subsidiary of InfraREIT Partners, LP.
Sharyland Holdings
On May 16, 2019, Sempra Energy acquired an indirect, 50% interest in Sharyland Holdings for $95 million (net of $7 million in post-closing adjustments) pursuant to the Securities Purchase Agreement. In connection with and prior to the consummation of the Securities Purchase Agreement, 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 interest in Sharyland Holdings as an equity method investment.
Sempra Mexico
Ductos y Energéticos del Norte, S. de R.L. de C.V.
On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50% interest in DEN, a JV that holds a 50% interest in the Los Ramones Norte pipeline through TAG JV, for a purchase price of $165 million (exclusive of $18 million of cash and cash equivalents acquired), plus the assumption of $96 million of short-term debt. This acquisition increased IEnova’s ownership interest in DEN through IEnova Pipelines from 50% to 100%, and increased IEnova’s indirect ownership interest in TAG JV from 25% to 50%. IEnova Pipelines previously accounted for its 50% interest in DEN as an equity method investment. At closing, DEN became a wholly owned, consolidated subsidiary of IEnova Pipelines. DEN will continue to account for its interest in TAG JV as an equity method investment. This acquisition also included a $66 million intangible asset that represents a favorable O&M agreement, which has an amortization period of 23 years.
Sempra Renewables
On July 10, 2017, Sempra Renewables paid $124 million in cash for an asset acquisition of a portfolio of four solar projects located in Fresno County, California, that were under construction. Completed in 2018, the facilities were sold to a subsidiary of Con Ed in December 2018, as we discuss below.
Sempra South American Utilities
Compañía Transmisora del Norte Grande S.A.
On December 18, 2018, Chilquinta Energía acquired a 100% interest in Compañía Transmisora del Norte Grande S.A. through a sales and purchase agreement with AES Gener S.A. and its subsidiary Sociedad Eléctrica Angamos S.A. We completed the acquisition for a purchase price of $226 million and paid $208 million (net of $18 million cash acquired) with available cash on hand at our former Sempra South American Utilities segment, which is presented in discontinued operations.
We accounted for this business combination using the acquisition method of accounting. At the acquisition date, we allocated the $208 million in cash paid to the identifiable assets acquired ($231 million) and liabilities assumed ($43 million) based on their
respective fair values, with the excess recognized as goodwill ($38 million), which are included below in the “Assets Held for Sale in Discontinued Operations” table. We consider the purchase price allocation at the acquisition date to be final.
DIVESTITURES
In June 2018, our board of directors approved a plan to divest certain non-utility natural gas storage assets in the southeast U.S., and all our U.S. wind and U.S. solar assets (collectively, the Assets). As a result, we recorded impairment charges totaling $1.5 billion ($900 million after tax and NCI) in June 2018, which included $1.3 billion ($755 million after tax and NCI) at Sempra LNG, included in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations, and $200 million ($145 million after tax) at Sempra Renewables, included in Equity Earnings on Sempra Energy’s Consolidated Statements of Operations. In December 2018, we reduced the impairment of $1.3 billion recorded at Sempra LNG in June 2018 by $183 million ($126 million after tax and NCI) as a result of the sales agreement for certain storage assets described below, resulting in a total impairment charge of $1.1 billion ($629 million after tax and NCI) for the year ended December 31, 2018. These impairment charges primarily represented an adjustment of the related assets’ carrying values to estimated fair values, less costs to sell when applicable, which we discuss in Notes 6 and 12.
Sempra Renewables
On December 13, 2018, Sempra Renewables completed the sale of the following assets to a subsidiary of Con Ed for cash proceeds of $1.6 billion:
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its operating solar assets, including assets that we owned through JVs or through tax equity arrangements (other than those interests held by tax equity investors);
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its solar and battery storage development projects; and
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its 50% interest in the Broken Bow 2 wind generation facility.
In 2018, we recognized a pretax gain of $513 million ($367 million after tax) in Gain on Sale of Assets on Sempra Energy’s Consolidated Statement of Operations.
The following table summarizes the deconsolidation of these subsidiaries in 2018.
On April 22, 2019, Sempra Renewables completed the sale of its remaining wind assets and investments to AEP 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 the 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.
Sempra LNG
On February 7, 2019, Sempra LNG 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, to an affiliate of ArcLight Capital Partners and received cash proceeds of $322 million, net of transaction costs. In January 2019, Sempra LNG completed the sale of other non-utility assets for $5 million.
DISCONTINUED OPERATIONS
On January 25, 2019, our board of directors approved a plan to sell our South American businesses. We determined that these businesses, which previously constituted the Sempra South American Utilities segment, and certain activities associated with those businesses, met the held-for-sale criteria. These businesses are presented as discontinued operations, as the planned sales represent a strategic shift that will have a major effect on our operations and financial results. We do not plan to have significant continuing involvement in or be able to exercise significant influence on the operating or financial policies of these operations after they are sold. Accordingly, the results of operations, financial position and cash flows for these businesses have been reclassified to discontinued operations for all periods presented.
Discontinued operations that were previously in the Sempra South American Utilities segment include our 100% interest in Chilquinta Energía in Chile, our 83.6% interest in Luz del Sur in Peru and our 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.
On September 27, 2019, we entered into a Purchase and Sale Agreement with China Yangtze Power International (Hongkong) Co., Limited to sell our equity interests in our Peruvian businesses, including our 83.6% interest in Luz del Sur and its indirect ownership interest in Tecsur, for an aggregate base purchase price of $3.59 billion, subject to customary closing adjustments for working capital and changes in net indebtedness. The sale is subject to various conditions to closing, including approvals from the Peruvian anti-trust authority and the Bermuda Monetary Authority. We expect the sale to close in the first half of 2020.
On October 12, 2019, we entered into a Purchase and Sale Agreement with State Grid International Development Limited to sell our equity interests in our Chilean businesses, including our 100% interest in Chilquinta Energía and Tecnored and our 50% interest in Eletrans, for an aggregate base purchase price of $2.23 billion, subject to customary adjustments for working capital and changes in net indebtedness and other adjustments. Chilquinta Energía also agreed to purchase the remaining 50% interest in Eletrans from Sociedad Austral de Electricidad S.A., contingent on the sale of our Chilean businesses to State Grid International Development Limited. This acquisition by Chilquinta Energía would result in State Grid International Development Limited acquiring 100% of Eletrans, which we do not expect will have a significant economic impact on the sale of our Chilean businesses. The sale of our Chilean businesses is subject to various conditions to closing, including approval by the Chilean anti-trust authority, certain Chinese regulatory approvals and approval by the Bermuda Monetary Authority, but is not subject to Chilquinta Energía purchasing the remaining 50% interest in Eletrans. We expect the sale to close in the first half of 2020.
Summarized results from discontinued operations were as follows:
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.
At December 31, 2019 and 2018, $551 million and $506 million, respectively, of cumulative foreign currency translation adjustments related to our South American businesses are included in AOCI.
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 Energy’s income tax on earnings from these equity method investees, other than Oncor Holdings as we discuss below, is included in Income Tax (Expense) Benefit on the Consolidated Statement of Operations. Our foreign equity method investees are corporations whose operations are generally 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 $2,823 million and $2,814 million higher than the underlying equity in the net assets of the investee at December 31, 2019 and 2018, respectively, due to $2,868 million of equity method goodwill and $69 million in basis differences in AOCI, offset by $114 million at December 31, 2019 and $123 million at December 31, 2018 due to a tax sharing liability to TTI under the tax sharing agreement.
(2)
The carrying value of our equity method investment is $42 million 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 $12 million higher than the underlying equity in the net assets of the investee due to the remeasurement of our retained investment to fair value in 2014.
(4)
The carrying value of our equity method investment is $5 million higher than the underlying equity in the net assets of the investee due to guarantees.
(5)
The carrying value of our equity method investment is $130 million higher than the underlying equity in the net assets of the investee due to equity method goodwill.
(6)
The carrying value of our equity method investment at December 31, 2018 was $169 million lower than the underlying equity in the net assets of the investee due to an other-than-temporary impairment recorded in 2018.
(7)
The carrying value of our equity method investment at December 31, 2018 was $31 million lower than the underlying equity in the net assets of the investee due to an other-than-temporary impairment recorded in 2018.
(8)
The carrying value of our equity method investment is $263 million and $246 million higher than the underlying equity in the net assets of the investee at December 31, 2019 and 2018, 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.
(1)
We provide our ETR calculation in Note 8.
(2)
Losses from equity method investment in 2018 include an other-than-temporary impairment charge, which we discuss below.
We disclose distributions received from our investments, by segment, in the table below.
At December 31, 2019 and 2018, our share of the undistributed earnings of equity method investments was $634 million and $332 million, respectively, including $501 million at December 31, 2019 in undistributed earnings from investments for which we have more than 50% equity interests.
SEMPRA TEXAS UTILITIES
Oncor Holdings
As we discuss in Note 5, on March 9, 2018, we completed the acquisition of an indirect, 100% interest in Oncor Holdings, which, at December 31, 2019, owns an 80.25% interest in Oncor. Sempra Energy 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. As we do not have the power to direct the significant activities of Oncor Holdings and Oncor, we account for our 100% ownership interest in Oncor Holdings as an equity method investment.
Oncor is a domestic partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra Energy. 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.
In 2019, we contributed cash of $1,587 million to Oncor, including $1,067 million to fund Oncor’s May 2019 acquisition of interests in InfraREIT and certain acquisition-related expenses. In 2018, we contributed $230 million in cash to Oncor in accordance with the terms of the Merger Agreement, which enabled Oncor to achieve its required capital structure calculated for regulatory purposes. In 2019 and 2018, Oncor Holdings distributed to Sempra Energy $246 million and $149 million, respectively, in dividends and $10 million and $18 million, respectively, in tax sharing payments.
Sharyland Holdings
As we discuss in Note 5, on May 16, 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 MEXICO
IMG JV
IEnova has a 40% interest in IMG JV, a JV with a subsidiary of TC Energy, 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 operation in September 2019. In 2018 and 2017, Sempra Mexico invested cash of $80 million and $72 million, respectively, in IMG JV.
DEN and TAG JV
On November 15, 2017, IEnova acquired the remaining 50% interest in DEN, and DEN became a consolidated subsidiary. Since the acquisition date, IEnova accounts for DEN’s 50% interest in TAG JV as an equity method investment. We discuss this acquisition in Note 5.
SEMPRA RENEWABLES
As a result of the plan of sale, Sempra Renewables recorded an other-than-temporary impairment on certain of our wind equity method investments totaling $200 million in 2018, which is included in Equity Earnings on Sempra Energy’s Consolidated Statement of Operations. Sempra Renewables completed the sales of all its operating solar assets, including its solar equity method investments and one wind equity method investment, in December 2018 and its remaining wind assets and investments in April 2019. We discuss these divestitures further in Note 5.
In 2018, Sempra Renewables invested cash of $5 million in its unconsolidated JVs.
SEMPRA LNG
Cameron LNG JV
Cameron LNG JV was formed in October 2014 among Sempra Energy and three project partners, TOTAL S.A., 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 is constructing a three-train natural gas liquefaction export facility with a nameplate capacity of 13.9 Mtpa of LNG, with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. In August 2019, the first of three trains commenced commercial operation under the JV’s tolling agreements. Prior to commencing commercial operation, Sempra LNG capitalized interest of $33 million in 2019 and $47 million in each of 2018 and 2017 related to this equity method investment. In 2019, 2018 and 2017, Sempra LNG invested cash of $77 million, $228 million and $1 million, respectively, in 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 are being used for financing the cost of development and construction of the three-train Cameron LNG 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 $3.0 billion of the uncovered bank facility portion of the Loan Facility Agreements in a private placement bond offering. The newly issued senior secured notes bear interest at a fixed weighted-average rate of 3.39% and have a weighted-average tenor of 15.4 years at December 31, 2019.
Interest. The weighted-average all-in cost of the loans that remain outstanding under the original Loan Facility Agreements (and based on certain assumptions as to timing of drawdown) 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. The original Loan Facility Agreements required Cameron LNG JV to hedge 50% of outstanding borrowings to fix the interest rate, beginning in 2016. The hedges are to
remain in place until the debt principal has been amortized by 50%. 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 3.72%.
Guarantees. In August 2014 and December 2019, Sempra Energy entered into agreements for the benefit of all of Cameron LNG JV’s creditors under the original Loan Facility Agreements and the newly issued senior secured notes, respectively. Pursuant to these agreements, Sempra Energy has severally guaranteed 50.2% of Cameron LNG JV’s obligations under the original Loan Facility Agreements and the newly issued senior secured notes, or a maximum amount of $4.0 billion. Guarantees for the remaining 49.8% of Cameron LNG JV’s senior secured financing have been provided by the other project owners. Sempra Energy’s agreements and guarantees will terminate upon financial completion of the three-train Cameron LNG project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operations and meeting certain operational performance tests. We expect the project to achieve financial completion and the guarantees to be terminated approximately nine months after all three trains achieve commercial operation. Sempra Energy recorded a liability of $82 million in October 2014 for the fair value of its obligations associated with the original Loan Facility Agreements, which constitute guarantees. This liability was fully amortized at December 31, 2019. Sempra Energy recorded a liability of $3 million in December 2019 for the fair value of its obligations associated with Cameron LNG JV’s newly issued senior secured notes, which also constitute guarantees. This liability will be reduced on a straight-line basis over the duration of the guarantees by increasing our investment in Cameron LNG JV.
In August 2014, Sempra Energy 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, Sempra Energy agreed to certain restrictions on its ability to dispose of Sempra Energy’s indirect fully diluted economic and beneficial ownership interests in Cameron LNG JV. These restrictions vary over time. Prior to financial completion of the three-train Cameron LNG project, Sempra Energy must retain 37.65% of such interest in Cameron LNG JV. Starting six months after financial completion of the three-train Cameron LNG project, Sempra Energy 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 Energy 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 on the due date; insolvency of Cameron LNG JV; abandonment of the project; expropriation; unenforceability or termination of the finance documents; and a failure to achieve financial completion of the project by a financial completion deadline date of September 30, 2021 (with up to an additional 365 days extension beyond such date permitted in cases of force majeure). A delay in construction that results in a failure to achieve financial completion of the project by this financial completion deadline date would therefore result in an event of default under Cameron LNG JV’s financing and a potential demand on Sempra Energy’s guarantees.
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 have been 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 Energy and the other project partners.
The security trustee under Cameron LNG JV’s financing can demand that a payment be made by Sempra Energy under its guarantees of Sempra Energy’s 50.2% share of senior debt obligations due and payable either on the date such amounts were due from Cameron LNG JV (taking into account cure periods) in the event of a failure by Cameron LNG JV to pay such senior debt obligations when they become due or within 10 business days in the event of an acceleration of senior debt obligations under the terms of the finance documents. If an event of default occurs under the Sempra Energy completion agreement, the security trustee can demand that Sempra Energy purchase its 50.2% share of all then outstanding senior debt obligations within five business days (other than in the case of a bankruptcy default, which is automatic).
RBS SEMPRA COMMODITIES
RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra Energy and RBS in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra Energy. 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 September 2018, we fully impaired our remaining equity method investment in RBS Sempra Commodities by recording a charge of $65 million in Equity Earnings on Sempra Energy’s Consolidated Statement of Operations. 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) 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 Energy’s other equity method investments.
(1)
On April 22, 2019, Sempra Renewables sold its remaining wind assets and investments to AEP. As of April 22, 2019, these wind assets and investments are no longer equity method investments.
(2)
On December 13, 2018, Sempra Renewables sold all its operating solar assets, including its solar equity method investments, and its 50% interest in the Broken Bow 2 wind power generation facility to a subsidiary of Con Ed. As of December 13, 2018, the solar equity method investments and Broken Bow 2 are no longer equity method investments.
(3)
On November 15, 2017, IEnova completed the asset acquisition of PEMEX’s 50% interest in DEN, increasing its ownership percentage to 100%. As of November 15, 2017, DEN is no longer an equity method investment.
(4)
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
LINES OF CREDIT
Primary U.S. Committed Lines of Credit
At December 31, 2019, Sempra Energy Consolidated had an aggregate of $6.7 billion in four primary U.S. committed lines of credit, which provide liquidity and support commercial paper.
(1)
Because the commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.
(2)
The facility also provides for issuance of $200 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding 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 the letter of credit commitment up to $500 million. No letters of credit were outstanding at December 31, 2019.
(3)
Commercial paper outstanding is before reductions of unamortized discount of $3 million at Sempra Global and negligible amounts at SDG&E and SoCalGas.
(4)
The facility also provides for issuance of $100 million of letters of credit on behalf of the borrowing utility with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, the borrowing utility has the right to increase the letter of credit commitment up to $250 million. No letters of credit were outstanding at December 31, 2019.
The principal terms of the primary U.S. committed lines of credit in the table above include the following:
▪
Each is a 5-year syndicated revolving credit agreement expiring in May 2024.
▪
Citibank N.A. serves as administrative agent for the Sempra Energy and Sempra Global facilities and JPMorgan Chase Bank, N.A. serves as administrative agent for the SDG&E and SoCalGas facilities.
▪
Each facility has a syndicate of 23 lenders. No single lender has greater than a 6% share in any facility.
▪
Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings in the case of the Sempra Energy and Sempra Global lines of credit, and with the borrowing utility’s credit rating in the case of SDG&E’s and SoCalGas’ lines of credit.
▪
Sempra Energy, SDG&E and SoCalGas each 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, 2019, each entity was in compliance with this ratio and all other financial covenants under its respective credit facility.
▪
Sempra Energy guarantees Sempra Global’s obligations under its credit facility.
Foreign Committed Lines of Credit
Our foreign operations in Mexico have additional general-purpose credit facilities aggregating $1.9 billion at December 31, 2019. The principal terms of these credit facilities are described below.
(1)
Five-year revolving credit facility with a syndicate of 10 lenders.
(2)
Three-year revolving credit facility with Scotiabank Inverlat, S.A. Withdrawals may be made for up to one year from April 11, 2019 in either U.S. dollars or Mexican pesos.
(3)
Two-year revolving credit facility with The Bank of Nova Scotia. Withdrawals may be made for up to two years from September 23, 2019 in U.S. dollars.
Letters of Credit
Outside of our domestic and foreign committed 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, 2019, we had approximately $647 million in standby letters of credit outstanding under these agreements.
WEIGHTED-AVERAGE INTEREST RATES
The weighted-average interest rates on the total short-term debt at December 31, 2019 and 2018 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)
This arrangement is now accounted for as an operating lease liability upon adoption of the lease standard on January 1, 2019. See Note 2.
(1)
Excludes finance lease obligations, discounts, and debt issuance costs.
Various long-term obligations totaling $11.6 billion at Sempra Energy Consolidated at December 31, 2019 are unsecured. This includes unsecured long-term obligations totaling $9 million at SoCalGas. There were no unsecured long-term obligations at SDG&E.
Callable Long-Term Debt
At the option of Sempra Energy, SDG&E and SoCalGas, certain debt at December 31, 2019 is callable subject to premiums:
First Mortgage Bonds
The California Utilities issue first mortgage bonds secured by a lien on utility plant assets. The California Utilities 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 $6.4 billion at SDG&E and $1.3 billion at SoCalGas at December 31, 2019.
SDG&E
In May 2019, SDG&E issued $400 million of 4.1% first mortgage bonds maturing in 2049. We received proceeds of $396 million (net of debt discount, underwriting discounts and debt issuance costs of $4 million). SDG&E used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.
As we discuss in “Variable Interest Entities” in Note 1, on August 23, 2019, SDG&E deconsolidated Otay Mesa VIE. Prior to deconsolidation, on August 14, 2019, OMEC LLC paid in full the $211 million outstanding balance on its variable-rate loan that was scheduled to mature in August 2024.
SoCalGas
In June 2019, SoCalGas issued $350 million of 3.95% first mortgage bonds maturing in 2050. We received proceeds of $345 million (net of debt discount, underwriting discounts and debt issuance costs of $5 million). SoCalGas used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.
In January 2020, SoCalGas issued $650 million of 2.55% first mortgage bonds maturing in 2030. We received proceeds of $643 million (net of debt discount, underwriting discounts and debt issuance costs of $7 million). SoCalGas used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes.
Other Long-Term Debt
Sempra Energy
In June 2019, we issued $758 million of 5.75%, junior subordinated notes maturing in 2079, with a par value of $25 per note. We received proceeds of $733 million (net of underwriting discounts and debt issuance costs of $25 million). We used the proceeds from the offering to repay outstanding commercial paper and for other general corporate purposes. We may redeem some or all of the notes before their maturity, as follows:
▪
on or after October 1, 2024, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest;
▪
before October 1, 2024, if the U.S. federal tax law or regulations are amended or certain other events occur such that there is more than insubstantial risk that interest payable on the notes would no longer be deductible for federal income tax purposes, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest; or
▪
before October 1, 2024, if a credit rating agency publicly changes certain equity credit methodology for securities such as these notes that results in a shortening of the length of time for equity credit initially assigned or lowers the equity credit initially assigned, at a redemption price equal to 102% of the principal amount, plus accrued and unpaid interest.
The notes are unsecured obligations and rank junior and subordinate in right of payment to our existing and future senior indebtedness. The notes will rank equally in right of payment 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 that we have or may incur and to all indebtedness and other liabilities of our subsidiaries.
Sempra Mexico
In November 2019, IEnova entered into a loan agreement with International Finance Corporation and North American Development Bank and, in December 2019, received proceeds of $190 million (net of debt issuance costs of $10 million) to fund the construction of certain solar generation projects in Mexico. The 15-year loan bears interest based on 6-month LIBOR plus 2.25% and matures in 2034. In November 2019, IEnova entered into a floating-to-fixed interest rate swap to hedge interest payments on the $200 million variable rate loan, resulting in an all-in fixed rate of 4.03%.
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 Mexico has similar flow-through treatment.
We record income tax (expense) benefit from the transactional effects of foreign currency and inflation. Such effects are partially mitigated by net gains (losses) from foreign currency derivatives that are hedging Sempra Mexico parent’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)
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, Net, on the Consolidated Statements of Operations from foreign currency derivatives that are partially hedging Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova.
(2)
Related to operations in Mexico.
In December 2017, the TCJA was signed into law. This legislation significantly changed the IRC. The TCJA reduced the U.S. statutory corporate income tax rate from 35% to 21%, effective January 1, 2018. Deferred income tax assets and liabilities, including NOLs, were remeasured at the income tax rate expected to apply when those temporary differences reverse. The effects of the change to the income tax rate were recognized in the period when the change was enacted. This remeasurement resulted in significant reductions in deferred income tax balances at Sempra Energy Consolidated, SDG&E and SoCalGas in 2017.
The remeasurement of deferred income tax balances at SDG&E and SoCalGas resulted in excess deferred income taxes that previously have been collected from ratepayers at the higher rate. As we discuss in Note 4, these excess deferred income taxes have been recorded as regulatory liabilities and will generally be refunded to ratepayers in accordance with the IRC’s normalization provisions and as determined by the CPUC and the FERC. 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, 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 TCJA imposed a one-time tax for deemed repatriation of cumulative undistributed earnings of non-U.S. subsidiaries. In addition to the deemed repatriation tax, we accrued U.S. state and non-U.S. withholding tax on our expected future repatriation of foreign undistributed earnings.
We recorded the effects of the TCJA in 2017 using our best estimates and the information available to us through the date those financial statements were issued. In 2018, we adjusted our 2017 provisional estimates and completed our accounting for the income tax effects of the TCJA.
The table below summarizes the effects of the TCJA in 2018 and 2017:
In January 2019, our board of directors approved a plan to sell our South American businesses, 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 and have recorded the following in discontinued operations in the year ended December 31, 2019:
▪
$89 million income tax benefit primarily related to outside basis differences existing as of the January 25, 2019 approval of our plan to sell our South American businesses; and
▪
$51 million income tax expense related to the increase in outside basis differences from 2019 earnings since January 25, 2019.
We expect to repatriate approximately $4 billion of foreign undistributed earnings in the foreseeable future, and have accrued $157 million of U.S. state deferred income tax liability for repatriations that we expect will begin in 2020 as cash is generated. In 2019 and 2018, we repatriated approximately $254 million and $338 million, respectively, to the U.S.
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, 2019. 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 table below presents the geographic components of pretax income.
(1)
See “Income Tax Expense (Benefit) and Effective Income Tax Rates” table above for calculation of pretax income.
U.S. pretax income was lower in 2018 compared to 2019 and 2017 due to the 2018 impairment of certain assets at Sempra LNG and Sempra Renewables (discussed in Notes 5 and 12), offset by the 2018 gain on the sale of assets at Sempra Renewables (discussed in Note 5) and the 2017 write-off of SDG&E’s wildfire regulatory asset (discussed 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, 2019 and 2018, includes $155 million and $141 million, respectively, recorded as a noncurrent asset and $2,577 million and $2,321 million, 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 Energy Consolidated” 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 Energy Consolidated accrued $1 million for interest expense and penalties at December 31, 2019 and 2018, respectively, on the Consolidated Balance Sheets, and recorded $1 million of interest expense and penalties in 2018 and negligible amounts in each of 2019 and 2017 on the Consolidated Statements of Operations. SDG&E and SoCalGas each accrued negligible amounts for interest expense and penalties at December 31, 2019 and 2018 on the Consolidated Balance Sheets, and recorded negligible amounts of interest expense and penalties in each of 2019, 2018 and 2017 on the Consolidated Statements of Operations.
INCOME TAX AUDITS
Sempra Energy 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 2015. We are subject to examination by major state tax jurisdictions for tax years after 2010. Certain major non-U.S. income tax returns for tax years 2012 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 1999 through 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 2015 and state tax years after 2010.
In addition, Sempra Energy has filed a protest to contest proposed state audit adjustments for tax years 2009 and 2010. The pre-2011 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:
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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 Energy and its consolidated subsidiaries.
Sempra Energy 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 members of the Sempra Energy board of directors who were participants 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 Energy 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 for retirees’ spouses.
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 Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $488 million and $416 million at December 31, 2019 and 2018, respectively.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Benefit Plan Amendments Affecting 2019 and 2018
In 2019 and 2018, 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 and $12 million at Sempra Energy and $3 million and $8 million at SDG&E in 2019 and 2018, respectively, and $2 million at SoCalGas in 2019.
Settlement Accounting for Lump Sum Payments
When applicable, we record settlement charges for lump sum payments from our nonqualified pension plans that are in excess of the respective plan’s service cost plus interest cost. Sempra Energy Consolidated recorded settlement charges of $24 million in 2019, Sempra Energy Consolidated and SDG&E recorded settlement charges of $12 million and $4 million, respectively, in 2018, and Sempra Energy Consolidated recorded settlement charges of $8 million in 2017.
Sale of Qualified Pension Plan Annuity Contracts
In March 2018, an insurance company purchased annuities for certain current annuitants in the SDG&E and SoCalGas qualified pension plans and assumed the obligation for payment of these annuities. At SDG&E in the first quarter of 2018 and at SoCalGas in the second quarter of 2018, the liability transferred for these annuities, plus the total year-to-date lump-sum payments, exceeded the settlement threshold, which triggered settlement accounting. This resulted in a reduction of the recorded pension liability and pension plan assets of $363 million at Sempra Energy Consolidated, including $132 million at SDG&E and $231 million at SoCalGas. This also resulted in settlement charges in net periodic benefit cost of $54 million at Sempra Energy Consolidated, including $22 million at SDG&E and $32 million at SoCalGas. The settlement charges were recorded as regulatory assets on the Consolidated Balance Sheets.
Acquisition
In March 2018, Sempra Energy completed the Merger, as we discuss in Note 5, and assumed unfunded other postretirement employee benefits obligations for health care and life insurance benefits, resulting in an increase of $21 million in the other postretirement benefit plan liability at Sempra Energy Consolidated.
In each of 2019 and 2018, we had $27 million in AOCI representing an actuarial loss related to Oncor’s pension plan.
Special Termination Benefits Affecting 2018 and 2017
In 2018, certain nonrepresented, and in 2017, certain represented, employees age 62 or older with 5 years of service or age 55 to 61 with 10 years of service that retired under the Voluntary Retirement Enhancement Program offered in these years received an additional postretirement health benefit in the form of a $100,000 Health Reimbursement Account. We treated the benefit obligation attributable to the Health Reimbursement Account as a special termination benefit. This resulted in increases to the recorded liability for PBOP and net periodic benefit cost of $5 million for Sempra Energy Consolidated, $3 million for SDG&E and $2 million for SoCalGas in 2018 and $18 million for each of Sempra Energy Consolidated and SoCalGas in 2017.
The Voluntary Retirement Enhancement Program resulted in a higher than expected number of retirements in 2017. As a result, the total lump-sum benefits paid from the Sempra Energy nonqualified and SoCalGas qualified pension plans in 2017 exceeded the settlement threshold, which triggered settlement accounting. This resulted in a reduction of the recorded pension liability and pension plan assets of $194 million at Sempra Energy Consolidated and $175 million at SoCalGas. This also resulted in settlement charges in net periodic benefit cost of $38 million at Sempra Energy Consolidated and $30 million at SoCalGas. The settlement charges at SoCalGas were recorded as regulatory assets on the Consolidated Balance Sheets. A measurement date of December 31, 2017 was used for the respective settlement accounting triggered as the year-to-date lump-sum benefit payments first exceeded the settlement threshold in December.
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 2019 and 2018, and a statement of the funded status at December 31, 2019 and 2018:
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 2019, 2018 and 2017, 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 Energy companies’ actual mortality experience, in our calculations for each of those years. Actuarial losses in pension plans at Sempra Energy Consolidated in 2019 were driven primarily by a decrease in discount rates and updated census data at Sempra Energy, SDG&E and SoCalGas, a decrease in the lump-sum conversion rate at SDG&E and updated salary scale assumptions at SoCalGas. These actuarial losses were partially offset by actuarial gains at SDG&E and SoCalGas due to a decrease in the interest crediting rate for the cash balance plans. Actuarial losses in PBOP plans at Sempra Energy Consolidated in 2019 were driven primarily by a decrease in discount rates at SDG&E and SoCalGas. These actuarial losses were partially offset by actuarial gains at SoCalGas, due to a reduction in the 2020 expected health care costs.
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 Energy Consolidated, 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.
We recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets or liabilities, respectively; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. The California Utilities 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.
The California Utilities 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
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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 the California Utilities 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.
Sempra Energy, 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 Energy, SDG&E, SoCalGas and IEnova. The following table shows the obligations of unfunded pension plans at December 31:
Sempra Energy, SDG&E and SoCalGas each have a funded other postretirement benefit plan. 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 Energy. 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.
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 we 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 Energy’s Pension Master Trust
Sempra Energy’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 the California Utilities’ PBOP plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra Energy.
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:
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35% domestic equity
▪
24% international equity
▪
18% long credit
▪
8% ultra-long duration government securities
▪
5% global real estate investment trusts
▪
5% return-seeking credit
▪
5% real 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 Energy 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 7% 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 5% and 9% 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 25% to return-seeking assets and 75% 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 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 Energy’s pension master trust and the trusts for the California Utilities’ 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.
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.
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. Investments in certain fixed income securities 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 for the remaining fixed income securities.
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.
Private Equity Funds - These funds consist of investments in private equities that are held by limited partnerships following various strategies, including private equity and corporate finance. These partnerships generally have limited lives of 10 years, after which liquidating distributions will be received. The value is determined based on the NAV of the proportionate share of an ownership interest in partners’ capital. Holdings in these types of private equity funds are negligible, as the funds are well past their expected investment term and have distributed the bulk of proceeds from investment sales.
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 Energy Consolidated. 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 2020:
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 Energy Consolidated, 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 Energy common stock held by the savings plans was $1.3 billion and $1.0 billion at December 31, 2019 and 2018, respectively.
NOTE 10. SHARE-BASED COMPENSATION
SEMPRA ENERGY EQUITY COMPENSATION PLANS
Sempra Energy has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra Energy. The plans permit a wide variety of share-based awards, including:
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nonqualified stock options
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incentive stock options
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restricted stock awards
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restricted stock units
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stock appreciation rights
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performance awards
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stock payments
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dividend equivalents
Eligible employees, including those from the California Utilities, participate in Sempra Energy’s share-based compensation plans as a component of their compensation package.
In the three years ended December 31, 2019, Sempra Energy had the following types of equity awards outstanding:
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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 (for awards granted in 2019) or over a four-year period (for awards granted in 2010 or earlier), and expire 10 years from the date of grant. Vesting and/or the ability to exercise may be accelerated upon a change in control, in accordance with severance pay agreements or in accordance with the terms of the grant. Options are subject to forfeiture or earlier expiration following termination of employment, subject to certain exceptions.
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Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra Energy common stock at the end of three-year (for awards granted during or after 2015) or four-year performance periods (for awards granted prior to 2015) based on Sempra Energy’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra Energy’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index and the S&P 500 Index. We use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our targets for awards that vest based on EPS growth.
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For awards granted in 2013 or earlier, if Sempra Energy’s total return to shareholders exceeds target levels, up to an additional 50% of the number of granted RSUs may be issued.
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For awards granted during or after 2014, up to an additional 100% of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.
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For awards granted in 2015 and 2016 and certain awards granted in 2017 and 2018 that vest based on Sempra Energy’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 Energy 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 Energy’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.
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Other Performance-Based Restricted Stock Units: RSUs were granted in 2014 and 2015 in connection with the creation of Cameron LNG JV.
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The 2014 awards vested in 2015 through 2017 as the Compensation Committee of Sempra Energy’s board of directors determined that the objectives of the JV were achieved. Those awards vested on the anniversary of the grant date over a period of either two or three years.
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The 2015 awards vested in 2019 as both of the following were achieved: (a) the Compensation Committee of Sempra Energy’s board of directors determined that Sempra Energy achieved positive cumulative net income for fiscal years 2015 through 2017 and (b) Cameron LNG JV commenced commercial operations of the first train.
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Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest over three-year service periods (for awards granted in 2019), or at the end of three-year (for awards granted during 2015 through 2018) or four-year service periods (for awards granted prior to 2015).
For RSU awards, vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable LTIP, in accordance with severance pay agreements, or at the discretion of the Compensation Committee of Sempra Energy’s board of directors. 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, 2019, 7,662,352 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 Energy 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 Energy plans’ corporate staff costs. Total share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows:
(1)
Includes activity of awards issued from the IEnova 2013 LTIP, which settle in cash upon vesting based on the price of IEnova’s common stock.
SEMPRA ENERGY 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 Energy’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. All nonqualified stock options granted prior to 2019 were fully vested and compensation cost on such stock options was fully recognized by December 31, 2014. In January 2019, Sempra Energy’s board of directors granted 261,075 nonqualified stock options that are exercisable over a three-year period. The weighted-average per-share fair value for options
granted was $13.20 in 2019. 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, 2019 and activity for the year then ended:
The aggregate intrinsic value at December 31, 2019 is the total of the difference between Sempra Energy’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:
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$4 million in 2019
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$9 million in 2018
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$9 million in 2017
A negligible amount of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2019 is expected to be recognized over a weighted-average period of 2.03 years.
We received cash of $3 million from stock option exercises during 2019.
SEMPRA ENERGY RESTRICTED STOCK UNITS
We use a Monte-Carlo simulation model to estimate the fair value of our RSUs that vest based on Sempra Energy’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra Energy 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, 2019 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 Energy exceeds target performance conditions.
In 2019, 2018 and 2017, the total fair value of RSU shares vested during the year was $36 million, $32 million and $45 million, respectively.
The $32 million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2019 is expected to be recognized over a weighted-average period of 2.07 years. The weighted-average per-share fair values for performance-based RSUs granted were $105.03 and $110.54 in 2018 and 2017, respectively. The weighted-average per-share fair values for service-based RSUs granted were $107.60 and $101.88 in 2018 and 2017, 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 our asset values may fall or our liabilities 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 have derivatives that are (1) cash flow hedges, (2) fair value hedges, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities 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). We classify cash flows from the principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt 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:
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The California Utilities 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.
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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.
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Sempra Mexico and Sempra LNG may use natural gas and electricity derivatives, as appropriate, 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 or in Energy-Related Businesses Cost of Sales on the Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico may also use natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Consolidated Statements of Operations.
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From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel and GHG allowances.
The following table summarizes net energy derivative volumes.
In addition to the amounts noted above, we use commodity derivatives to manage risks associated with the physical locations of contractual obligations and assets, such as natural gas purchases and sales.
INTEREST RATE DERIVATIVES
We are exposed to interest rates primarily as a result of our current and expected use of financing. The California Utilities, as well as Sempra Energy 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. Separately, Otay Mesa VIE entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.
The following table presents the net notional amounts of our interest rate derivatives, excluding JVs.
(1)
Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE. On August 14, 2019, OMEC LLC paid in full its variable-rate loan and terminated its interest rate swaps.
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 Mexico 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 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 utilize foreign currency derivatives to hedge exposure to fluctuations in the Peruvian Sol related to the sale of our operations in Peru.
The following table presents the net notional amounts of our foreign currency derivatives, excluding JVs.
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, as the cash collateral was in excess of liability positions.
(1)
Included in Current Assets: Fixed-Price Contracts and Other Derivatives for SDG&E.
(2)
Normal purchase contracts previously measured at fair value are excluded.
(1)
Included in Current Assets: Fixed-Price Contracts and Other Derivatives for SDG&E.
(2)
Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(3)
Normal purchase contracts previously measured at fair value are excluded.
The table below 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. On August 14, 2019, OMEC LLC paid in full its variable-rate loan and terminated its interest rate swaps.
For Sempra Energy Consolidated, we expect that net losses of $26 million, which are 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. 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, 2019 is approximately 15 years for Sempra Energy Consolidated. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 20 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 Energy Consolidated, 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 Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at December 31, 2019 and 2018 was $21 million and $16 million, respectively. For SoCalGas, the total fair value of this group of derivative instruments in a net liability position at December 31, 2019 and 2018 was $4 million and $5 million, respectively. At December 31, 2019, if the credit ratings of Sempra Energy or SoCalGas were reduced below investment grade, $21 million and $4 million, respectively, of additional assets could be required to be posted as collateral for these derivative contracts.
For Sempra Energy Consolidated, 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, 2019 and 2018. 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 and $10 million investment at December 31, 2019 and 2018, respectively, measured at NAV):
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Nuclear decommissioning trusts reflect the assets of SDG&E’s NDT, excluding cash balances. 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).
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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.”
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Rabbi Trust investments include marketable securities 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). These investments in marketable securities were negligible at both December 31, 2019 and 2018.
(1)
Excludes cash balances and cash equivalents.
(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 cash balances and cash equivalents.
(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
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 Energy Consolidated 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 were as follows:
A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. We summarize long-term, fixed-price electricity position volumes in Note 11.
Realized gains and losses associated with CRRs and long-term 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.
Fair Value of Financial Instruments
The fair values of certain of our financial instruments (cash, accounts and notes 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 reductions of unamortized discount and debt issuance costs of $225 million and excluding finance lease obligations of $1,289 million.
(2)
Before reductions of unamortized discount and debt issuance costs of $48 million and excluding finance lease obligations of $1,270 million.
(3)
Before reductions of unamortized discount and debt issuance costs of $34 million and excluding finance lease obligations of $19 million.
(4)
Level 3 instruments include $220 million related to Otay Mesa VIE.
(5)
Before reductions of unamortized discount and debt issuance costs of $206 million and excluding build-to-suit arrangement and capital lease obligations of $1,413 million.
(6)
Before reductions of unamortized discount and debt issuance costs of $49 million and excluding capital lease obligations of $1,272 million.
(7)
Before reductions of unamortized discount and debt issuance costs of $32 million and excluding capital lease obligations of $3 million.
We provide the fair values for the securities held in the NDT related to SONGS in Note 15.
NON-RECURRING FAIR VALUE MEASURES
Sempra Mexico
TdM
In 2017, while TdM was held for sale, Sempra Mexico received a purchase price offer for TdM resulting from negotiations with an active market participant. This new market information indicated that the fair value of TdM was lower than its carrying value at June 30, 2017. As a result, in the second quarter of 2017, Sempra Mexico further reduced the carrying value of TdM by recognizing a noncash impairment charge of $71 million in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations. A purchase price offer is considered to be a Level 2 input in the fair value hierarchy, as it represents an observable pricing input. TdM was reclassified to held and used in June 2018 when management terminated the sales process.
Sempra Renewables
U.S. Wind Investments
As we discuss in Notes 5 and 6, in June 2018, our board of directors approved a plan to sell all our wind and solar equity method investments at Sempra Renewables. Because of our expectation of a shorter holding period as a result of this plan of sale, we evaluated the recoverability of the carrying amounts of each of these investments and concluded there was an other-than-temporary impairment on certain of our wind equity method investments totaling $200 million ($145 million after tax), which we
recorded in Equity Earnings on Sempra Energy’s Consolidated Statement of Operations for the year ended December 31, 2018. We measured the estimated fair value of $145 million at June 25, 2018 using a discounted cash flow model including significant unobservable inputs, adjusted for our applicable ownership percentages, which is a Level 3 measurement in the fair value hierarchy. The key inputs to the methodology were contracted and merchant pricing, and the discount rate. Sempra Renewables completed the sale of its interests in these wind equity method investments in April 2019.
Sempra LNG
Non-Utility Natural Gas Storage Assets
As we discuss in Note 5, in June 2018, our board of directors approved a plan to sell Mississippi Hub, our 90.9% ownership interest in Bay Gas and other non-utility assets (the non-utility natural gas storage assets). We also own a 75.4% interest in LA Storage, a salt cavern development project in Cameron Parish, Louisiana. The LA Storage project also includes an existing 23.3-mile pipeline header system that is not currently contracted.
Because of the plan of sale, we considered a market participant’s view of the total value of the non-utility natural gas storage assets and determined that their fair value, less costs to sell, may be less than their carrying value. Additionally, our inability to secure customer contracts that would support further investment in LA Storage led us to assess and conclude that the full carrying value of these other U.S. midstream assets may not be recoverable. As a result, on June 25, 2018, we recorded an impairment of $1.3 billion ($755 million after tax and NCI) in Impairment Losses on Sempra Energy’s Consolidated Statement of Operations.
We measured the estimated fair value of $190 million at June 25, 2018 using a discounted cash flow approach. This approach included unobservable inputs, resulting in a Level 3 measurement in the fair value hierarchy. We considered a market participant’s view of the values of the non-utility natural gas storage assets based on an estimation of future net cash flows. To estimate future net cash flows, we considered the non-utility natural gas storage assets’ prospects for generating revenues and cash flows beyond their existing contracted capacity and tenors, including natural gas price volatility and seasonality factors, as well as discount rates commensurate with the risks inherent in the cash flows.
On January 1, 2019, Sempra LNG entered into an agreement to sell Mississippi Hub and Bay Gas to an affiliate of ArcLight Capital Partners for $332 million, subject to working capital adjustments and $20 million representing Sempra LNG’s purchase of the 9.1% minority interest in Bay Gas immediately prior to and included as part of the sale. On February 7, 2019, Sempra LNG completed this sale. Additionally, in December 2018, Sempra LNG entered into an agreement to sell other non-utility assets for $5 million; such sale was completed in January 2019. We considered the assets’ sales prices negotiated with active market participants to be a relevant and material data input. Accordingly, we updated our fair value analysis to reflect the Level 2 market participant input as the primary indicator of fair value. As a result, on December 31, 2018, we reduced the impairment of $1.3 billion recorded on June 25, 2018 by $183 million ($126 million after tax and NCI), resulting in a total impairment of $1.1 billion ($629 million after tax and NCI) for the year ended December 31, 2018, based on a fair value of $337 million for these non-utility natural gas storage assets.
The table below summarizes significant inputs impacting our non-recurring fair value measures. Additional discussions about the related transactions are provided in Note 5, and as applicable, in Note 6.
(1)
Generally, significant increases (decreases) in this input in isolation would result in a significantly higher (lower) fair value measurement.
(2)
An increase in the discount rate would result in a decrease in fair value.
NOTE 13. PREFERRED STOCK
Sempra Energy and SDG&E are authorized to issue up to 50 million and 45 million shares of preferred stock, respectively. At December 31, 2019 and 2018, 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.
SEMPRA ENERGY MANDATORY CONVERTIBLE PREFERRED STOCK
In January 2018, we issued 17,250,000 shares of our 6% mandatory convertible preferred stock, series A (series A preferred stock) in a registered public offering at $100.00 per share (or $98.20 per share after deducting underwriting discounts), including 2,250,000 shares purchased by the underwriters from us as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of series A preferred stock has a liquidation value of $100.00. We used the net proceeds of approximately $1.69 billion (net of underwriting discounts and equity issuance costs of $32 million) to fund a portion of the Merger Consideration, as we discuss in Note 5.
In July 2018, we issued 5,750,000 shares of our 6.75% mandatory convertible preferred stock, series B (series B preferred stock) in a registered public offering at $100.00 per share (or $98.35 per share after deducting underwriting discounts), including 750,000 shares purchased by the underwriters from us as a result of fully exercising their option to purchase such shares from us solely to cover overallotments. Each share of series B preferred stock has a liquidation value of $100.00. We used the net proceeds of approximately $565 million (net of underwriting discounts and equity issuance costs of $10 million) to repay commercial paper, to fund working capital and for other general corporate purposes.
Mandatory Conversion
Unless earlier converted, each share of the series A preferred stock and series B preferred stock will automatically convert on the mandatory conversion date of January 15, 2021 and July 15, 2021, respectively. The number of shares of our common stock issuable on conversion of each series of preferred stock will be determined based on the volume-weighted average market value per share of our common stock over the 20-consecutive trading day period beginning on and including the 21st scheduled trading day immediately preceding January 15, 2021 for the series A preferred stock and July 15, 2021 for the series B preferred stock. The following table illustrates the conversion rate per share of each series of preferred stock, subject to certain anti-dilution adjustments.
Conversion at the Option of the Holder
Generally, and subject to the terms of the respective series of preferred stock, at any time prior to January 15, 2021 for the series A preferred stock and July 15, 2021 for the series B preferred stock, holders may elect to convert each share of their preferred stock into shares of our common stock at the minimum conversion rate, which could result in an aggregate of approximately 13.2 million common shares with respect to conversion of series A preferred stock and 4.2 million common shares with respect to conversion of series B preferred stock, if all outstanding preferred stock under each series were converted early, subject to anti-dilution adjustments. Further, if holders elect to convert any shares of either series of preferred stock during a specified period beginning on the effective date of a fundamental change, as defined in the certificate of determination of preferences of the respective series of preferred stock, such shares of preferred stock will be converted into shares of our common stock at a fundamental change conversion rate, and the holders will also be entitled to receive a fundamental change dividend make-whole amount and accumulated dividend amount.
Dividends
Dividends on each series of preferred stock are payable quarterly on a cumulative basis when, as and if declared by our board of directors. The first quarterly dividend for the series A preferred stock and series B preferred stock was paid on April 15, 2018 and October 15, 2018, respectively. We may pay quarterly declared dividends in cash or, subject to certain limitations, in shares of our common stock, no par value, or in any combination of cash and shares of our common stock. Shares of common stock used to pay dividends will be valued at 97% of the volume-weighted average price per share over the five-consecutive trading day period beginning on, and including the sixth trading day prior to, the applicable dividend payment date. The holders of each series of preferred stock do not have voting rights with respect to their preferred stock. However, under certain circumstances including nonpayment of dividends for six 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 each series of preferred stock, voting together as a single class with holders of any and all other outstanding preferred stock of equal rank having similar voting rights, will be entitled to elect two directors to fill such newly created directorships. This right shall terminate when all accumulated dividends have been paid in full and the authorized number of directors shall automatically decrease by two, subject to the revesting of that right in the event of each subsequent nonpayment.
Ranking
Each series of preferred stock will rank with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:
▪
senior to our common stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;
▪
on parity with each series of preferred stock, including our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;
▪
junior to our capital stock established in the future, if the terms provide that such class of series of new capital stock will rank senior to the series A preferred stock and series B preferred stock;
▪
junior to our existing and future indebtedness and other liabilities; and
▪
structurally subordinated to any 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 ENERGY - SHAREHOLDERS’ EQUITY AND EARNINGS PER COMMON SHARE
SEMPRA ENERGY COMMON STOCK OFFERINGS
In January 2018, we completed the offering of 26,869,158 shares of our common stock, no par value, in a registered public offering at $107.00 per share (approximately $105.07 per share after deducting underwriting discounts), with 23,364,486 shares pursuant to forward sale agreements. We received net proceeds totaling approximately $2.8 billion to fully settle these shares, as follows:
▪
$367 million (net of underwriting discounts and equity issuance costs of $8 million) to cover overallotment shares of 3,504,672 in the first quarter of 2018 at a settlement price of $105.07 per share;
▪
$900 million (net of underwriting discounts of $16 million) from the settlement of 8,556,630 shares in the first quarter of 2018 at a forward sale price of $105.18 per share;
▪
$800 million (net of underwriting discounts of $14 million) from the settlement of 7,651,671 shares in the second quarter of 2018 at forward sale prices ranging from $104.53 to $104.58 per share; and
▪
$728 million (net of underwriting discounts of $13 million) from the settlement of 7,156,185 shares in the third quarter of 2019 at a forward sale price of $101.74 per share.
In July 2018, we completed the offering of 11,212,500 shares of our common stock, no par value, in a registered public offering at $113.75 per share (approximately $111.87 per share after deducting underwriting discounts), with 9,750,000 shares pursuant to forward sale agreements. We received net proceeds totaling approximately $1.2 billion to fully settle these shares, as follows:
▪
$164 million (net of underwriting discounts and equity issuance costs of $3 million) to cover overallotment shares of 1,462,500 in the third quarter of 2018 at a settlement price of $111.87 per share; and
▪
$1,066 million (net of underwriting discounts of $18 million) from the settlement of 9,750,000 shares in the fourth quarter of 2019 at a forward sale price of $109.33 per share.
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 617 in 2019, 641 in 2018 and 609 in 2017. 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 Energy 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 excludes potentially dilutive shares of 80,281 for 2019, 20,814 for 2018 and 237,741 for 2017 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. As of December 31, 2019, we have fully
settled all forward sale agreements and those shares are included in weighted-average shares common shares outstanding for basic EPS.
The potentially dilutive impact from mandatory convertible preferred stock that we issued in 2018 is calculated under the if-converted method. The computation of diluted EPS for the years ended December 31, 2019 and 2018 excludes 17,471,375 and 17,197,035 potentially dilutive shares, respectively, because to include them would be antidilutive for those periods. However, these shares could potentially dilute basic EPS in the future. We discuss the 2018 issuances of our mandatory convertible preferred stock in Note 13.
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)
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 Energy’s and SDG&E’s Consolidated Statements of Operations.
SONGS STEAM GENERATOR REPLACEMENT PROJECT
The replacement steam generators, which caused a water leak due to unexpected tube wear, were designed and provided by MHI. In 2013, Edison instituted arbitration proceedings against MHI seeking recovery of damages resulting from the issues with the steam generators used in SONGS Units 2 and 3. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents.
In March 2017, the International Chamber of Commerce International Court of Arbitration Tribunal (the Tribunal) overseeing the arbitration found MHI liable for breach of contract, subject to a contractual limitation of liability, and rejected claimants’ other claims. The Tribunal awarded $118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95% of its arbitration costs. The damage award is offset by these costs, resulting in a net award of approximately $60 million in favor of the SONGS co-owners. SDG&E’s specific allocation of the damage award was $24 million reduced by costs awarded to MHI of approximately $12 million, resulting in a net damage award of $12 million, which was paid by MHI to SDG&E in March 2017. In accordance with the Amended Settlement Agreement discussed below, SDG&E recorded
the proceeds from the MHI arbitration by reducing O&M for previously incurred legal costs of $11 million, and shared the remaining $1 million equally between ratepayers and shareholders.
SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION INTO THE SONGS OUTAGE
In 2012, in response to the SONGS outage, the CPUC issued the SONGS OII, which was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of the outage.
In 2014, the CPUC issued a final decision approving an Amended Settlement Agreement that provided for various disallowances, refunds and rate recoveries, including authorizing SDG&E to recover in rates its remaining investment in SONGS, excluding its investment in the Steam Generator Replacement Project.
In 2016, the CPUC issued two procedural rulings: the first, to reopen the record of the OII to address the issue of whether the Amended Settlement Agreement is reasonable and in the public interest, and the second, directing parties to the SONGS OII to determine whether an agreement could be reached to modify the Amended Settlement Agreement previously approved by the CPUC, to resolve allegations that unreported ex parte communications between Edison and the CPUC resulted in an unfair advantage at the time the settlement agreement was negotiated.
In July 2018, the CPUC approved a Revised Settlement Agreement among SDG&E, Edison, Cal PA, TURN and other intervenors that resolved all issues under consideration in the SONGS OII and made one modification to the Amended Settlement Agreement to remove the requirement to fund a GHG emissions reduction research program. In August 2018, parties to the Revised Settlement Agreement submitted a notice that they accepted the settlement agreement, as modified.
In connection with the Revised Settlement Agreement, and in exchange for the release of certain SONGS-related claims, SDG&E and Edison entered into the Utility Shareholder Agreement, described below.
Disallowances, Refunds and Recoveries
Under the Revised Settlement Agreement, SDG&E and Edison ceased rate recovery of SONGS costs as authorized under the Amended Settlement Agreement as of December 19, 2017, when the present value of their combined remaining SONGS regulatory assets equaled $775 million, of which $152 million represents SDG&E’s share. Under the Utility Shareholder Agreement, Edison is obligated to pay SDG&E the full amount of SDG&E’s revenue requirement not recovered from ratepayers, as described below. In October 2018, SDG&E began refunding to customers SONGS-related amounts recovered in rates after December 19, 2017.
Utility Shareholder Agreement
In January 2018, SDG&E and Edison entered into the Utility Shareholder Agreement under which Edison has an obligation to compensate SDG&E for the revenue requirement amounts that SDG&E will no longer recover because of the Revised Settlement Agreement. In exchange for Edison’s reimbursement, the parties mutually released each other from all claims that each party had or could have asserted related to the steam generator replacement failure and its aftermath. The Utility Shareholder Agreement became effective upon CPUC approval of the Revised Settlement Agreement. Edison’s payment obligation commenced in October 2018, and amounts are due to SDG&E quarterly thereafter until April 2022. At December 31, 2019, SDG&E has a receivable from Edison, including accrued interest, totaling $86 million, with $38 million classified as current and $48 million classified as noncurrent. This receivable reflects amounts Edison is obligated to pay to SDG&E in lieu of amounts SDG&E would have collected from ratepayers associated with the SONGS regulatory asset.
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. We expect the majority of the dismantlement work to take 10 years after receipt of the required permits. The coastal development permit was issued in October 2019. The Samuel Lawrence Foundation filed a writ petition under the California Coastal Act in LA Superior Court in December 2019. The petition seeks to invalidate the permit and to obtain injunctive relief to stop decommissioning work. We expect major decommissioning work to begin in 2020, unless the court issues an injunction. 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 contract price.
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. The amounts 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 Energy 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. SDG&E has received authorization from the CPUC to access NDT funds of up to $455 million for 2013 through 2019 SONGS decommissioning costs. SDG&E has filed for authorization with the CPUC to withdraw up to $109 million from the NDT for forecasted 2020 SONGS Units 2 and 3 costs as decommissioning costs are incurred.
In December 2016, the IRS and the U.S. Department of the Treasury issued proposed 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 proposed regulations state that costs related to the construction and maintenance of independent spent fuel management installations are included in the definition of “nuclear decommissioning costs.” The proposed regulations will be effective prospectively once they are finalized. SDG&E is awaiting the adoption of, or additional refinement to, the proposed regulations before determining whether the proposed regulations will allow SDG&E to timely access the NDT funds for reimbursement or payment of the spent fuel management costs incurred in 2017 and subsequent years. Further clarification of the proposed regulations could enable SDG&E to access the NDT to recover spent fuel management 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. The IRS held public hearings on the proposed regulations in October 2017. It is unclear when clarification of the proposed regulations might be provided or when the proposed regulations will be finalized.
Nuclear Decommissioning Trusts
The amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.
The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 12.
(1)
Maturity dates are 2021-2050.
(2)
Maturity dates are 2020-2056.
(3)
Maturity dates are 2020-2072.
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 Energy’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 AND SPENT NUCLEAR FUEL
The present value of SDG&E’s ARO related to decommissioning costs for the SONGS units was $611 million at December 31, 2019. That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The ARO for all three units is based on a cost study prepared in 2017 that is pending CPUC approval. 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. SDG&E’s share of total decommissioning costs in 2019 dollars is approximately $834 million. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $89 million in 2020, $82 million in 2021, $83 million in 2022, $63 million in 2023, $46 million in 2024, and $739 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 or temporarily in spent fuel pools. In October 2015, the CCC approved Edison’s application for the proposed expansion of the ISFSI at SONGS. The ISFSI expansion began construction in 2016 and the transfer of the spent nuclear fuel from Units 2 and 3 to the ISFSI began in 2018. Edison suspended this transfer in August 2018 due to an incident that was subsequently resolved to the NRC’s satisfaction according to the NRC’s supplemental inspection report released in July 2019. Edison resumed spent fuel transfer operations in July 2019. 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. 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, including SDG&E, also maintain nuclear property damage insurance at $1.5 billion, with a $500 million property damage sublimit on the ISFSI, which exceeds the minimum federal requirements of $1.06 billion. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated 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 $10.4 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 applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.
At December 31, 2019, loss contingency accruals for legal matters, including associated legal fees, that are probable and estimable were $68 million for Sempra Energy Consolidated and $21 million for SoCalGas. Amounts for Sempra Energy Consolidated and SoCalGas include $10 million for matters related to the Aliso Canyon natural gas storage facility gas leak, which we discuss below. We discuss our policy regarding accrual of legal fees in Note 1.
SDG&E
2007 Wildfire Litigation and Net Cost Recovery Status
SDG&E has resolved all litigation associated with three wildfires that occurred in October 2007.
As a result of a CPUC decision denying SDG&E’s request to recover wildfire costs, SDG&E wrote off the wildfire regulatory asset, resulting in a charge of $351 million ($208 million after tax) in the third quarter of 2017. SDG&E applied to the CPUC for rehearing of its decision but, in July 2018, the CPUC denied SDG&E’s rehearing request. In November 2018, the California Court of Appeal denied SDG&E’s petition to reverse the CPUC’s decision. In January 2019, the California Supreme Court denied SDG&E’s petition to reverse the decisions of the CPUC and the California Court of Appeal. In October 2019, the U.S. Supreme Court declined to review the decision, effectively ending SDG&E’s efforts to recover the wildfire regulatory asset.
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 in “Civil and Criminal Litigation” and “Regulatory Proceedings,” 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 and Accounting Impact.”
Civil and Criminal Litigation. As of February 21, 2020, 393 lawsuits, including approximately 36,000 plaintiffs, are pending against SoCalGas related to the Leak, some of which have also named Sempra Energy. All these cases, other than a matter brought by the Los Angeles County District Attorney and the federal securities class action discussed below, are coordinated before a single court in the LA Superior Court for pretrial management.
In November 2017, in the coordinated proceeding, individuals and business entities filed a Third Amended Consolidated Master Case Complaint for Individual Actions, through which their separate lawsuits will be 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, with certain causes of action also naming Sempra Energy. 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 (including penalties associated with Proposition 65 claims alleging violation of requirements for warning about certain chemical exposures), and attorneys’ fees. The court has scheduled an initial trial for June 24, 2020 for a small number of randomly selected individual plaintiffs.
In January 2017, two consolidated class action complaints were filed against SoCalGas and Sempra Energy, 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). Both complaints assert claims for strict liability for ultra-hazardous activities, negligence and violation of the California Unfair Competition Law. The Property Class Action also asserts claims for negligence per se, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action also asserts a claim for negligent interference with prospective economic advantage. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. In May 2019, the California Supreme Court ruled that the purely economic damages alleged in the Business Class Action are not recoverable, and in September 2019, in accordance with the ruling, the LA Superior Court dismissed the strict liability, negligence and negligent interference with prospective economic advantage causes of action in the Business Class Action complaint.
Three property developers filed complaints in July and October of 2018 against SoCalGas and Sempra Energy alleging causes of action for strict liability, negligence per se, negligence, continuing nuisance, permanent nuisance and violation of the California Unfair Competition Law, 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 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 Energy 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 attorney’s fees.
Five shareholder derivative actions are also pending alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas, four of which were joined in a Consolidated Shareholder Derivative Complaint in August 2017. In November 2019, the Superior Court dismissed the complaints on the grounds that the plaintiffs failed to adequately plead their claims, but gave leave for them to amend the complaints to cure the defects. In February 2020, an amended complaint was filed.
In addition, a federal securities class action alleging violation of the federal securities laws was filed against Sempra Energy 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. The plaintiffs have appealed the dismissal.
Three actions by public entities were filed, including complaints by the County of Los Angeles, on behalf of itself and the people of the State of California, the California Attorney General, acting in an independent capacity and on behalf of the people of the State of California and CARB, and the Los Angeles City Attorney alleging public nuisance, unfair competition, and violations of California Health and Safety Code provisions regarding discharge of contaminants, among other things, which sought injunctive relief, abatement, civil penalties and damages. In February 2019, the LA Superior Court approved a settlement between SoCalGas and the Los Angeles City Attorney’s Office, the County of Los Angeles, the California Office of the Attorney General and CARB under which SoCalGas made payments and agreed to provide funding for environmental projects totaling $120 million, including $21 million in civil penalties, as well as other safety-related commitments.
In February 2016, the Los Angeles County District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for, among other things, alleged failure to provide timely notice of the Leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a). Pursuant to a settlement agreement with the Los Angeles County District Attorney’s Office, SoCalGas agreed to plead no contest to the notice charge and pay the maximum fine of $75,000, penalty assessments of approximately $233,500, and operational commitments estimated to cost approximately $6 million, reimbursements and assessments in exchange for the Los Angeles County District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint (the District Attorney Settlement). SoCalGas completed the commitments and obligations under the District Attorney Settlement, and in November 2016, the LA Superior Court approved the settlement and entered judgment on the notice charge. Certain individuals who objected to the settlement petitioned the Court of Appeal to vacate the judgment, contending they should be granted restitution. In July 2019, the Court of Appeal denied the petition in part, but remanded the matter to the trial court to give the petitioners an opportunity to prove damages stemming from only the three-day delay in reporting the Leak.
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, which address most of the root cause of the Leak identified during Blade’s investigation.
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 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 Safety Enforcement Division (SED) and Blade during the pre-formal investigation, and whether any of the mitigation proposed by Blade should be implemented to the extent not already done. In November 2019, SED, based largely on the Blade report, alleged a total of 330 violations, asserting that SoCalGas violated California Public Utilities Code Section 451 and failed to cooperate in the investigation and to keep proper records. Hearings in the first phase of the OII are scheduled to begin in April 2020. The second phase will consider whether SoCalGas should be sanctioned for the Leak and what penalties, if any, should be imposed for any violations proven in the first phase, as well as 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. In a January 2016 emergency proclamation, the Governor ordered the CPUC to ensure that SoCalGas covers costs related to the Leak and its response, while protecting ratepayers. In addition, CalGEM is investigating the Leak.
In February 2017, the CPUC opened a proceeding pursuant to SB 380 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 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 will evaluate 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. The CPUC has indicated that it expects to issue its report relative to Phase 2 in 2020. In December 2019, the CPUC added a third phase to consider alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated in either 2027 or 2045.
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, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31, 2019, the Aliso Canyon natural gas storage facility had a net book value of $769 million. Any significant impairment of this asset, or higher operating costs and additional capital expenditures incurred by SoCalGas which may not be recoverable in customer rates, could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations, financial condition and cash flows.
Cost Estimates and Accounting Impact. SoCalGas has incurred significant costs 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, 2019, SoCalGas estimates its costs related to the Leak are $1,116 million (the cost estimate), which includes $1,086 million of costs recovered or probable of recovery from insurance. This estimate may rise significantly as more information becomes available. Approximately 51% of the cost estimate is for the temporary relocation program (including cleaning costs and certain labor costs). A substantial portion of the cost estimate has been paid, and $9 million is accrued as Reserve for Aliso Canyon Costs and $7 million is accrued in Deferred Credits and Other as of December 31, 2019 on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets.
Except for the amounts paid or estimated to settle certain actions as described above, the cost estimate does not include litigation or regulatory costs as it is not possible at this time to predict the outcome of these actions or reasonably estimate the costs to defend or resolve the actions or the amount of damages, restitution, or civil, administrative or criminal fines, sanctions, penalties or other costs or remedies that may be imposed or incurred, which could be significant. The cost estimate also does not include certain other costs incurred by Sempra Energy associated with defending against shareholder derivative lawsuits and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate.
Excluding directors’ and officers’ liability insurance, we have at least four kinds of insurance policies that together we estimate provide between $1.2 billion to $1.4 billion in insurance coverage, depending on the nature of the claims. We have received insurance payments for many of the costs described above, including temporary relocation and associated processing costs, control-of-well expenses, costs of the government-ordered response to the Leak, legal costs and lost gas. We intend to pursue the full extent of our insurance coverage for the costs we have incurred or may incur. There can be no assurance that we will be successful in obtaining additional insurance recovery for these costs. If any costs are not covered by insurance (including any costs in excess of applicable policy limits), if there are significant 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 could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
As of December 31, 2019, we recorded the expected recovery of the cost estimate related to the Leak of $339 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets. This amount is net of insurance retentions and $747 million of insurance proceeds we received through December 31, 2019. If we were to conclude that this receivable or a portion of it is no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings, which could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Sempra Mexico
Energía Costa Azul. IEnova has been engaged in a long-running land dispute relating to property adjacent to its ECA LNG Regasification facility near Ensenada, Mexico. A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of SEDATU in 2006 to issue a title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and IEnova challenged
the ruling, due to lack of notification of the underlying process. In May 2019, a federal court in Mexico reversed the ruling. IEnova expects additional proceedings regarding the claims.
Several administrative challenges are pending in Mexico before the Mexican environmental protection agency and the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization issued to the ECA LNG Regasification 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.
Additionally, in August 2018, a claimant filed a challenge in the federal district court in Ensenada, Baja California in relation to the environmental and social impact permits issued to ECA LNG JV for the potential liquefaction-export project in September 2017 and December 2017, respectively, to allow natural gas liquefaction activities at the ECA LNG Regasification facility. The court issued a provisional injunction in September 2018 and maintained that provisional injunction at an April 2019 hearing. In December 2018, the relevant Mexican regulators approved modifications to the environmental permit that facilitate the development of the proposed natural gas liquefaction facility by ECA LNG JV in two phases. In May 2019, the court canceled the provisional injunction. The claimant has appealed the court’s decision. That appeal and the claimant’s underlying challenge to the permits remain pending.
Cases involving two parcels of real property have been filed against the ECA LNG Regasification facility. In one case, filed in the federal Agrarian Court in 2006, the plaintiffs seek to annul the recorded property title for a parcel on which the ECA LNG Regasification facility is situated and to obtain possession of a different parcel that allegedly sits in the same place. Another civil complaint filed in the state court was served in April 2012 seeking to invalidate the contract by which the ECA LNG Regasification facility purchased another of the parcels, on the grounds the purchase price was unfair; the plaintiff filed a second complaint in 2013 in the federal Agrarian Court seeking an order that SEDATU issue title to her. In January 2016, the federal Agrarian Court ruled against the plaintiff, and the plaintiff appealed the ruling. In May 2018, the state court dismissed the civil complaint, and the plaintiff has appealed. IEnova expects further proceedings on these two matters.
An unfavorable final decision on these property disputes or permit challenges could materially and adversely affect our existing natural gasification operations and our planned natural gas liquefaction projects currently in development at the ECA LNG Regasification facility and potential ECA LNG JV liquefaction-export project.
Guaymas-El Oro Segment of the Sonora Pipeline. IEnova’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, IEnova 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, IEnova reported damage to the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory that has made that section inoperable since August 23, 2017 and, as a result, IEnova 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 IEnova from making repairs to put the pipeline back in service. In July 2019, a federal district court ruled in favor of IEnova 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 IEnova 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.
IEnova 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 on August 22, 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 IEnova 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. In January 2020, IEnova and the CFE agreed to extend the January 15, 2020 new service start date to May 15, 2020. 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 May 15,
2020 and the parties do not agree on a new service start date, IEnova retains the right to terminate the contract and seek to recover its reasonable and documented costs and lost profits.
If IEnova is unable to make such repairs and resume operations in the Guaymas-El Oro segment of the Sonora pipeline within this time frame or if IEnova terminates the contract and is unable to obtain recovery, there may be a material adverse impact on Sempra Energy’s results of operations and cash flows and our ability to recover the carrying value of our investment. The Sasabe-Puerto Libertad-Guaymas segment of the Sonora pipeline remains in full operation and is not impacted by these developments.
Sur de Texas-Tuxpan Marine Pipeline. Sempra Mexico has a 40% interest in IMG JV, a JV with a subsidiary of TC Energy, to build, own and operate the Sur de Texas-Tuxpan natural gas marine pipeline in Mexico. The JV has an agreement to provide the CFE with natural gas transportation services under a 25-year agreement, denominated in U.S. dollars. IMG JV previously received force majeure payments from the CFE from November 2018 through April 2019, after construction delays extended the commercial operation date. In June 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 JV and the CFE amended the gas transportation services agreement to modify the tariff structure and extend the term of the contract by 10 years, which ended the arbitration process. Construction and commissioning activities on the pipeline were completed in June 2019 and, in September 2019, IMG JV received acceptance from the CFE allowing the pipeline to enter commercial operation and for service under the gas transportation contract to commence.
Other Litigation
Sempra Energy holds an NCI in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. NatWest Markets plc, formerly RBS, 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 has since been sold to JP Morgan 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. After paying the assessment, RBS filed a Notice of Appeal of the assessment with the First-Tier Tribunal. Trial on the matter has been scheduled between November 2, 2020 and December 11, 2020.
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, at the close of which the Liquidating Companies asserted that the Defendants were liable to the Liquidating Companies in the amount of £71.5 million (approximately $95 million in U.S. dollars at December 31, 2019) for dishonest assistance and, to the extent that claim is unsuccessful, to the liquidators in the same amount under the U.K. Insolvency Act of 1986. If the High Court of Justice finds the Defendants liable, it will determine the amount. JP Morgan has notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from Sempra Energy and RBS.
While the ultimate outcome remains uncertain, in the third quarter of 2018, we impaired our remaining $65 million equity method investment in RBS Sempra Commodities.
Certain EFH subsidiaries that we acquired as part of the Merger are defendants in personal injury lawsuits brought in state courts throughout the U.S. As of February 21, 2020, 275 such lawsuits are pending, with 182 such lawsuits having been served. These cases allege 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 seek compensatory and punitive damages. 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. We anticipate additional lawsuits will be filed. None of these claims or lawsuits were discharged in the EFH bankruptcy proceeding.
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 and power generating facilities 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 and peaker plant facilities.
Some of our leases include options to extend the lease terms for up to 25 years, while others include options to terminate the lease within one year. Our lease liabilities and ROU assets are based on lease terms that may include such options to extend or terminate the lease when it is reasonably certain that we will exercise that 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 4% 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 $326 million in 2020, $328 million in 2021, $328 million in 2022, $327 million in 2023, $328 million in 2024 and $3,707 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 ROU asset for our right to use the underlying asset, which is initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. Like other long-lived assets, 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. The California Utilities 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. The California Utilities 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)
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 was as follows:
The table below presents the maturity analysis of our lease liabilities and reconciliation to the present value of lease liabilities:
Leases that Have Not Yet Commenced
SDG&E and SoCalGas have lease agreements for future acquisitions of fleet vehicles with an aggregate maximum lease limit of $174 million. SDG&E and SoCalGas have utilized $54 million and $72 million, respectively, of these maximum limits as of December 31, 2019.
Sempra LNG has a lease agreement for office space in Houston, Texas that will commence in February 2020. We expect the future fixed lease payments to begin in 2021 and to be $1 million in 2021, $2 million per year in 2022 through 2024, and $16 million thereafter until expiration in 2031.
Lease Disclosures Under Previous U.S. GAAP
Rent expense for operating leases was as follows:
The annual amortization charge for PPAs accounted for as capital leases at both Sempra Energy Consolidated and SDG&E was $11 million and $8 million in 2018 and 2017, respectively. The annual depreciation charge for fleet vehicles and other assets in 2018 and 2017 was $8 million and $3 million, respectively, at Sempra Energy Consolidated, including $2 million and $1 million, respectively, at SDG&E and $6 million and $2 million, respectively, at SoCalGas.
The table below presents the future minimum lease payments under previous U.S. GAAP:
Lessor Accounting
Sempra Mexico is a lessor for certain of its natural gas and ethane pipelines, compressor stations and LPG storage facilities. These operating leases expire at various dates from 2021 through 2039.
Sempra Mexico 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 evaluate the underlying asset for impairment. Certain of our leases contain rate adjustments or are based on foreign currency exchange rates that may result in lease payments received that vary from one period to the next.
We provide information below for leases for which we are the lessor.
(1)
Included in Machinery and Equipment - Pipelines and Storage within the major functional categories of PP&E.
(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, primarily based on published monthly bid-week indices.
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 2031.
Sempra LNG has various capacity agreements for natural gas storage and transportation. Transportation costs on these agreements vary based on pipeline capacity.
In May 2017, Sempra LNG received settlement proceeds of $57 million from a breach of contract claim against a counterparty in bankruptcy court. Of the total proceeds, $47 million related to a charge we recorded in 2016 resulting from the permanent release of certain pipeline capacity. Sempra LNG recorded the settlement proceeds as a reduction to Energy-Related Businesses Cost of Sales on Sempra Energy’s Consolidated Statement of Operations in 2017.
Payments on our natural gas contracts could exceed the minimum commitment based on portfolio needs. At December 31, 2019, 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 Energy Consolidated and SoCalGas were as follows:
LNG Purchase Agreement
Sempra LNG has a sale and purchase agreement for the supply of LNG to the ECA LNG Regasification facility. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2020 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 LNG.
At December 31, 2019, the following LNG commitment amounts are based on the assumption that all cargoes, less those already confirmed to be diverted, under the agreement are delivered:
Actual LNG purchases in 2019, 2018 and 2017 have been significantly lower than the maximum amount provided under the agreement due to the customer electing to divert most cargoes as allowed by the agreement.
Purchased-Power Contracts
For 2020, SDG&E expects to meet its customer power requirements from the following resource types:
▪
Long-term contracts: 27% (of which 26% is provided by renewable energy contracts expiring on various dates through 2041)
▪
Other SDG&E-owned generation and tolling contracts: 59%
▪
Spot market purchases: 14%
Payments on our purchased-power contracts could exceed the minimum commitments based on energy needs. At December 31, 2019, the future minimum payments under long-term purchased-power contracts for Sempra Energy Consolidated and SDG&E are as follows:
(1)
Excludes purchase agreements accounted for as 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. Total payments under purchased-power contracts for Sempra Energy Consolidated and SDG&E were $744 million in 2019, $712 million in 2018 and $781 million in 2017.
Construction and Development Projects
Sempra Energy Consolidated has various capital projects in progress in the U.S. and Mexico. Our total contractual commitments at December 31, 2019 under these projects are approximately $1,212 million, requiring future payments of $990 million in 2020, $56 million in 2021, $33 million in 2022, $18 million in 2023, $14 million in 2024 and $101 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to such projects.
SDG&E
At December 31, 2019, SDG&E has commitments to make future payments of $57 million for construction projects that include:
▪
$49 million for infrastructure improvements for electric and natural gas transmission and distribution systems; and
▪
$8 million related to spent fuel management at SONGS.
SDG&E expects future payments under these contractual commitments to be $20 million in 2020, $19 million in 2021, $14 million in 2022, $1 million in 2023, $1 million in 2024 and $2 million thereafter.
Sempra Mexico
At December 31, 2019, Sempra Mexico has commitments to make future payments of $976 million for construction projects that include:
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$567 million for liquid fuels terminals;
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$283 million for natural gas pipelines and ongoing maintenance services; and
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$126 million for renewables projects.
Sempra Mexico expects future payments under these contractual commitments to be $791 million in 2020, $37 million in 2021, $19 million in 2022, $17 million in 2023, $13 million in 2024 and $99 million thereafter.
Sempra LNG
At December 31, 2019, Sempra LNG has commitments to make future payments of $179 million primarily for LNG liquefaction development costs and natural gas transportation projects. The future payments under these contractual commitments are all expected to be made in 2020.
OTHER COMMITMENTS
SDG&E
We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 15.
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 2020 through 2024 and $282 million thereafter, subject to escalation of 2% per year, for a remaining 50-year period. At December 31, 2019, the present value of these future payments of $121 million has been recorded as a regulatory asset as the amounts represent a cost that is expected to be recovered from customers in the future.
Sempra LNG
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 LNG would sell to the California Utilities, subject to annual CPUC approval, up to 500 MMcf per day of regasified LNG from Sempra Mexico’s ECA LNG Regasification 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 LNG 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 LNG and Sempra Mexico. The California Utilities’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates.
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 the California Utilities, 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 Aliso Canyon natural gas storage facility leak as we discuss above or resolved during the last three years, include (1) investigation and remediation of the California Utilities’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by the California Utilities 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, 2019 of the California Utilities’ 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 the present value of 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, 2019. Of the total liability, $15 million is recorded on a discounted basis, with discount rates ranging from 1.5% to 3%.
(1)
Sites for which we have been identified as a PRP.
(2)
Includes $7 million, $1 million and $6 million classified as current liabilities, and $44 million, $4 million and $39 million classified as noncurrent liabilities on Sempra Energy’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 at the Aliso Canyon natural gas storage facility. 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 $85 million, of which $46 million has been incurred through December 31, 2019 and $39 million is accrued for remaining costs through 2053, which is recoverable in rates and included in noncurrent Regulatory Assets on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets. Work on the artificial reef that was dedicated in 2008 continues.
The CCC has stated that it now requires an expansion of the reef because the existing reef may be too small to consistently meet the performance standards. In 2018, the CPUC approved a joint motion filed by SDG&E, Edison, TURN and Cal PA requesting approval of a settlement agreement that amends the rate recovery application and allows costs to be recorded to a memorandum account until rate recovery is approved. In August 2019, Edison and SDG&E submitted an updated cost forecast to the CPUC for rate recovery approval when the project’s coastal development permit was approved. The CPUC approved the updated cost forecast in December 2019, with rates going into effect on January 1, 2020. SDG&E’s share of the reef expansion costs currently forecasted through September 2020 is approximately $4 million, of which $3 million has been incurred through December 31, 2019 and $1 million is payable for remaining costs through September 2020.
We expect future payments related to our environmental liabilities on an undiscounted basis to be $9 million in 2020, $32 million in 2021, $2 million in 2022, $2 million in 2023, $1 million in 2024 and $50 million thereafter.
NOTE 17. SEGMENT INFORMATION
We have five separately managed reportable segments, as follows:
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SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
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SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
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Sempra Texas Utilities holds our investment in Oncor Holdings, which, at December 31, 2019, owns an 80.25% interest in Oncor, a regulated electric transmission and distribution utility serving customers in the north-central, eastern and western and panhandle regions of Texas, and our indirect, 50% interest in Sharyland Holdings, which owns a regulated electric transmission and distribution utility serving customers near the Texas-Mexico border. As we discuss in Note 5, we acquired our investment in Oncor Holdings in March 2018 and Sharyland Holdings in May 2019.
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Sempra Mexico develops, owns and operates, or holds interests in, natural gas, electric, LNG, LPG, ethane and liquid fuels infrastructure, and has marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico.
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Sempra LNG (previously known as Sempra LNG & Midstream) develops projects for the export of LNG, holds an interest in a facility for the export of LNG, owns and operates natural gas pipelines, and buys, sells and transports natural gas through its
marketing operations, all within the U.S. and Mexico. In February 2019, we completed the sale of our natural gas storage assets at Mississippi Hub and Bay Gas.
In December 2018, Sempra Renewables completed the sale of all its operating solar assets, solar and battery storage development projects and one wind generation facility. 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 has been reclassified to discontinued operations for all periods presented. The information in the tables below excludes amounts from discontinued operations unless otherwise noted.
We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings and cash flows. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC and 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 $5 million, $69 million, $120 million and $222 million for 2019; $4 million, $64 million, $114 million and $215 million for 2018; and $7 million, $74 million, $103 million and $266 million for 2017 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG, respectively.
(2)
As we discuss in Note 2, in accordance with adoption of the lease standard on January 1, 2019, on a prospective basis, a significant portion of finance lease costs for PPAs that have historically been presented in Cost of Electric Fuel and Purchased Power are now presented in Interest Expense.
(3)
Includes net PP&E and investments.
(4)
Amounts are based on where the revenue originated, after intercompany eliminations.
NOTE 18. QUARTERLY FINANCIAL DATA (UNAUDITED)
We provide quarterly financial information for Sempra Energy Consolidated, SDG&E and SoCalGas below:
(1)
EPS is computed independently for each of the quarters and therefore may not sum to the total for the year.
(2)
In the quarters ended September 30, 2019 and December 31, 2018, due to the dilutive effect of certain mandatory convertible preferred stock, the numerator used to calculate diluted EPS included an add-back of related mandatory convertible preferred stock dividends declared in those quarters.
(3)
In the quarter ended June 30, 2018, the total weighted-average potentially dilutive securities were not included in the computation of losses per common share since to do so would have decreased the loss per share.
In April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments and recognized a pretax gain on sale of $61 million ($45 million after tax). We discuss the sale and related gain in Note 5.
In June 2018, we recorded impairment charges totaling $1.5 billion ($900 million after tax and NCI), which included $1.3 billion ($755 million after tax and NCI) at Sempra LNG and $200 million ($145 million after tax) at Sempra Renewables. In December
2018, we reduced the impairment charge at Sempra LNG by $183 million ($126 million after tax and NCI). We discuss the impairments in Notes 5 and 12. In December 2018, we completed the sale of our U.S. operating solar assets, solar and battery storage development projects, as well as an interest in one wind facility, and recognized a pretax gain on sale of $513 million ($367 million after tax). We discuss the sale and related gain in Note 5.
In September 2018, we impaired our remaining equity method investment in RBS Sempra Commodities by recording a charge of $65 million in Equity Earnings. We discuss matters related to RBS Sempra Commodities further in Note 16.
SoCalGas recognizes annual authorized revenue for core natural gas customers using seasonal factors established in the Triennial Cost Allocation Proceeding. Accordingly, a significant portion of SoCalGas’ annual earnings are recognized in the first and fourth quarters each year.
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See Notes to Condensed Financial Information of Parent.
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See Notes to Condensed Financial Information of Parent.
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See Notes to Condensed Financial Information of Parent.
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See Notes to Condensed Financial Information of Parent.
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SEMPRA ENERGY
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 Energy Consolidated, except that Sempra Energy accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information.
Other Income, Net, on the Condensed Statements of Operations includes:
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$61 million, $(6) million and $56 million of gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans in 2019, 2018 and 2017, respectively;
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$3 million and $50 million net gains primarily from the settlement of foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova in 2018 and 2017, respectively; and
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$15 million losses in 2019 from foreign currency derivatives used to hedge exposure of fluctuations in the Peruvian Sol related to the sale of our operations in Peru.
Sempra Energy received cash dividends from its consolidated subsidiaries totaling $150 million, $300 million and $450 million in 2019, 2018 and 2017, respectively.
Additional information on Sempra Energy’s foreign currency derivatives is provided in Note 11 of the Notes to Consolidated Financial Statements.
NOTE 2. NEW ACCOUNTING STANDARDS
We describe below and in Note 2 of the Notes to Consolidated Financial Statements recent pronouncements that have had a significant effect on Sempra Energy’s financial condition, results of operations, cash flows or disclosures.
ASU 2016-02, “Leases,” ASU 2018-10, “Codification Improvements to Topic 842, Leases” and ASU 2018-11, “Leases (Topic 842): Targeted Improvements” (collectively referred to as the “lease standard”): We adopted the lease standard on January 1, 2019 using the optional modified retrospective transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. The adoption of the lease standard had a material impact on our balance sheet at January 1, 2019 due to the initial recognition of ROU assets and lease liabilities for operating leases.
The following table shows the increases (decreases) on our balance sheet at January 1, 2019 from adoption of the lease standard.
(1)
Included in Other Long-Term Assets.
(2)
Included in Shareholders’ Equity.
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As a result of the adoption of the lease standard, we derecognized the asset and liability associated with our corporate headquarters building in accordance with the transition provisions for build-to-suit arrangements. On a prospective basis, we will account for the corporate headquarters building lease as an operating lease. The initial impact is included in the above table.
ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”: We adopted ASU 2018-02 on January 1, 2019 and reclassified the income tax effects of the TCJA from AOCI to retained earnings. The impact from adoption of ASU 2018-02 on January 1, 2019 was an increase of $14 million to beginning Retained Earnings and Accumulated Other Comprehensive Loss.
ASU 2019-12, “Simplifying the Accounting for Income Taxes”: ASU 2019-12 simplifies certain areas of accounting for income taxes. In addition to other changes, this standard amends ASC 740, “Income Taxes,” as follows:
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removes the exception to the incremental approach for intraperiod tax allocation when there is a loss from continuing operations and income or a gain from other items, including discontinued operations or other comprehensive income;
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simplifies the recognition of deferred taxes related to basis differences as a result of ownership changes in investments;
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specifies an entity is not required to allocate the consolidated amount of current and deferred tax expense to a legal entity that is not subject to tax in its separate financial statements; and
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requires an entity to reflect the effect of an enacted change in tax laws or rates in the annual ETR computation in the interim period that includes the enactment date.
For public entities, ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim periods therein, with early adoption permitted. The transition method related to the amendments made by ASU 2019-12 vary based on the nature of the change. We are currently evaluating our planned adoption date and the effect of the standard on our ongoing financial reporting.
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NOTE 3. 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.
(2)
This arrangement is now accounted for as an operating lease liability upon adoption of the lease standard on January 1, 2019. See Note 2.
Maturities of long-term debt at December 31, 2019 are $1.4 billion in 2020, $1.6 billion in 2021, $500 million in 2022, $1.0 billion in 2023, $500 million in 2024 and $5.4 billion thereafter.
Additional information on Sempra Energy’s long-term debt is provided in Note 7 of the Notes to Consolidated Financial Statements.
NOTE 4. COMMITMENTS AND CONTINGENCIES
Sempra Energy has an operating lease commitment related to its corporate headquarters building of approximately $267 million. Sempra Energy expects payments for its operating lease to be $10 million in 2020, $11 million in 2021, $11 million in 2022, $11 million in 2023, $12 million in 2024 and $212 million thereafter.
For other contingencies and guarantees related to Sempra Energy, refer to Notes 6, 7 and 16 of the Notes to Consolidated Financial Statements.
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