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OPERATIONS - Acquisitions (Details)
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each Class
Trading Symbol
Name
of Each Exchange on Which Registered
SEMPRA ENERGY:
iCommon Stock, without par value
iSRE
iNew
York Stock Exchange
i6.75% Mandatory Convertible Preferred Stock, Series B, $100 liquidation preference
iSREPRB
iNew
York Stock Exchange
i5.75% Junior Subordinated Notes Due 2079, $25 par value
iSREA
iNew
York Stock Exchange
SAN DIEGO GAS & ELECTRIC COMPANY:
None
SOUTHERN CALIFORNIA GAS COMPANY:
None
1
SECURITIES
REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Title of Each Class
SEMPRA ENERGY:
None
SAN DIEGO GAS & ELECTRIC COMPANY:
None
SOUTHERN CALIFORNIA GAS COMPANY:
i6% Preferred Stock, $25
par value
i6% Preferred Stock, Series A, $25 par value
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.
Sempra Energy
iYes☒
No ☐
San Diego Gas & Electric Company
Yes ☐
iNo☒
Southern California Gas Company
Yes ☐
iNo☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Sempra
Energy
Yes ☐
iNo☒
San Diego Gas & Electric Company
Yes ☐
iNo☒
Southern California Gas Company
Yes ☐
iNo☒
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that
the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
iYes☒
No ☐
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be
submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit such files).
iYes☒
No ☐
Indicate by check mark whether the registrant is a large accelerated filer,
an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Sempra Energy:
☒iLarge
Accelerated Filer
☐ Accelerated Filer
☐ Non-accelerated Filer
i☐ Smaller Reporting Company
i☐Emerging Growth Company
San Diego Gas & Electric Company:
☐ Large Accelerated Filer
☐ Accelerated Filer
☒iNon-accelerated
Filer
i☐Smaller Reporting Company
i☐ Emerging Growth Company
Southern
California Gas Company:
☐ Large Accelerated Filer
☐ Accelerated Filer
☒iNon-accelerated Filer
i☐Smaller Reporting Company
i☐ Emerging Growth Company
2
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Sempra Energy
☐
San Diego Gas & Electric Company
☐
Southern California Gas Company
☐
Indicate by check mark whether the registrant
has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act by the registered public accounting firm that prepared or issued its audit report.
Sempra Energy
i☒
San Diego Gas &
Electric Company
i☒
Southern California Gas Company
i☒
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Sempra Energy
Yesi☐
No ☒
San Diego Gas & Electric Company
Yesi☐
No
☒
Southern California Gas Company
Yesi☐
No ☒
Aggregate market value of the voting and non-voting common equity
held by non-affiliates of the registrant as of June 30, 2020:
Sempra Energy
$i34.3 billion (based on the price at which the common equity was last sold as of the last business day of the most recently completed second fiscal quarter)
San Diego Gas & Electric Company
$i0
Southern
California Gas Company
$i0
Common Stock outstanding, without par value, as of February 22, 2021:
Sempra
Energy
i302,591,374 shares
San Diego Gas & Electric Company
Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Southern California Gas Company
Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy
SAN
DIEGO GAS & ELECTRIC COMPANY 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).
Portions of the Sempra Energy proxy statement
to be filed for its May 2021 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.
Portions of the Southern California Gas Company information statement to be filed for its June 2021 annual meeting of shareholders are incorporated by reference into Part III of this annual report on Form 10-K.
This combined Form 10-K is separately filed by Sempra Energy, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any one of these individual reporting entities is filed by such entity on its own behalf. Each entity makes statements herein only as to itself and its consolidated subsidiaries and makes no statement whatsoever as to any other entity.
You should read this report in its entirety as it pertains to each respective reporting entity. No one section of the report deals with all aspects of the subject matter. Separate Part II – Items 6 and 8 are provided for each reporting
entity, except for the Notes to Consolidated Financial Statements in Part II – Item 8. The Notes to Consolidated Financial Statements for all of the reporting entities are combined. All Items other than Part II – Items 6 and 8 are combined for the three reporting entities.
4
The following terms and abbreviations appearing in this report have the meanings indicated below.
GLOSSARY
2016
GRC FD
final decision in the California Utilities’ 2016 General Rate Case
2019 GRC FD
final decision in the California Utilities’ 2019 General Rate Case
AB
California Assembly Bill
AFUDC
allowance for funds used during construction
AMP
Arrearage Management Payment Plan
AOCI
accumulated other comprehensive income (loss)
ARO
asset
retirement obligation
ASC
Accounting Standards Codification
ASR
accelerated share repurchase
ASU
Accounting Standards Update
Bay Gas
Bay Gas Storage Company, Ltd.
Bcf
billion cubic feet
Bechtel
Bechtel Oil, Gas and Chemicals, Inc.
Blade
Blade
Energy Partners
bps
basis points
Cal PA
California Public Advocates Office
CalGEM
California Geologic Energy Management Division (formerly known as Division of Oil, Gas, and Geothermal Resources or DOGGR)
California Utilities
San Diego Gas & Electric Company and Southern California Gas Company, collectively
Cameron LNG JV
Cameron LNG Holdings, LLC
CARB
California
Air Resources Board
CCA
Community Choice Aggregation
CCC
California Coastal Commission
CCM
cost of capital adjustment mechanism
CEC
California Energy Commission
CENACE
Centro Nacional de Control de Energía (Mexico’s National Center for Energy Control)
CENAGAS
Centro Nacional de Control de Gas
CFE
Comisión Federal de Electricidad (Mexico’s Federal Electricity Commission)
CFIN
Cameron LNG FINCO, LLC, a wholly owned and unconsolidated affiliate of Cameron LNG JV
Chilquinta Energía
Chilquinta Energía, S.A. and its subsidiaries
CNBV
Comisión Nacional Bancaria y de Valores (Mexico’s National Banking and Securities Commission)
COFECE
Comisión Federal de Competencia Económica (Mexico’s Competition
Commission)
COVID-19
coronavirus disease 2019
CPUC
California Public Utilities Commission
CRE
Comisión Reguladora de Energía (Mexico’s Energy Regulatory Commission)
CRR
congestion revenue right
DA
Direct Access
DEN
Ductos y Energéticos del Norte, S. de R.L. de C.V.
DOE
U.S.
Department of Energy
DOT
U.S. Department of Transportation
DWR
California Department of Water Resources
ECA LNG
ECA LNG Phase 1 and ECA LNG Phase 2, collectively
ECA LNG Phase 1
ECA LNG Holdings B.V.
ECA LNG Phase 2
ECA LNG II Holdings B.V.
ECA Regas Facility
Energía Costa Azul, S. de R.L.
de C.V. LNG regasification facility
Ecogas
Ecogas México, S. de R.L. de C.V.
Edison
Southern California Edison Company, a subsidiary of Edison International
EFH
Energy Future Holdings Corp. (renamed Sempra Texas Holdings Corp.)
Eletrans
Eletrans S.A., Eletrans II S.A. and Eletrans III S.A., collectively
EMA
energy management agreement
Enova
Enova
Corporation
EPA
U.S. Environmental Protection Agency
EPC
engineering, procurement and construction
EPS
earnings per common share
5
GLOSSARY (CONTINUED)
ERCOT
Electric
Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
ERR
eligible renewable energy resource
ESJ
Energía Sierra Juárez, S. de R.L. de C.V.
ETR
effective income tax rate
Exchange Act
Securities Exchange Act of 1934, as amended
FERC
Federal Energy Regulatory Commission
Fitch
Fitch
Ratings
FTA
Free Trade Agreement
Gazprom
Gazprom Marketing & Trading Mexico S. de R.L. de C.V.
GCIM
Gas Cost Incentive Mechanism
GHG
greenhouse gas
GRC
General Rate Case
HMRC
United Kingdom’s Revenue and Customs Department
IEnova
Infraestructura
Energética Nova, S.A.B. de C.V.
IEnova Pipelines
IEnova Pipelines, S. de R.L. de C.V.
IMG JV
Infraestructura Marina del Golfo
InfraREIT
InfraREIT, Inc.
IOU
investor-owned utility
IRC
U.S. Internal Revenue Code of 1986 (as amended)
IRS
Internal Revenue Service
ISFSI
independent
spent fuel storage installation
ISO
Independent System Operator
JV
joint venture
kV
kilovolt
kW
kilowatt
kWh
kilowatt hour
LA Storage
LA Storage, LLC
LA Superior Court
Los Angeles
County Superior Court
Leak
the leak at the SoCalGas Aliso Canyon natural gas storage facility injection-and-withdrawal well, SS25, discovered by SoCalGas on October 23, 2015
LIBOR
London Interbank Offered Rate
LNG
liquefied natural gas
LPG
liquid petroleum gas
LTIP
long-term incentive plan
Luz
del Sur
Luz del Sur S.A.A. and its subsidiaries
MD&A
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Pipeline and Hazardous Materials Safety Administration
PP&E
property, plant and equipment
PPA
power purchase agreement
PRP
Potentially Responsible Party
PSEP
Pipeline Safety Enhancement Plan
PUCT
Public
Utility Commission of Texas
PURA
Public Utility Regulatory Act
RBS
The Royal Bank of Scotland plc
RBS SEE
RBS Sempra Energy Europe
RBS Sempra Commodities
RBS Sempra Commodities LLP
REC
renewable energy certificate
ROE
return on equity
ROU
right-of-use
RPS
Renewables
Portfolio Standard
RSU
restricted stock unit
S&P
Standard & Poor’s
Saavi Energía
Saavi Energía S. de R.L. de C.V.
SB
California Senate Bill
SCAQMD
South Coast Air Quality Management District
SDG&E
San Diego Gas & Electric Company
SDTS
Sharyland
Distribution & Transmission Services, L.L.C. (a subsidiary of InfraREIT)
SEC
U.S. Securities and Exchange Commission
SED
Safety and Enforcement Division of the CPUC
SEDATU
Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexican agency in charge of agriculture, land and urban development)
Sempra Global
holding company for most of Sempra Energy’s subsidiaries not subject to California or Texas utility regulation
SENER
Secretaría
de Energía de México (Mexico’s Ministry of Energy)
series A preferred stock
6% mandatory convertible preferred stock, series A
series B preferred stock
6.75% mandatory convertible preferred stock, series B
series C preferred stock
Sempra Energy’s 4.875% fixed-rate reset cumulative redeemable perpetual preferred stock, series C
Sharyland Holdings
Sharyland Holdings, L.P.
Sharyland Utilities
Sharyland Utilities,
L.L.C.
Shell Mexico
Shell México Gas Natural, S. de R.L. de C.V.
SoCalGas
Southern California Gas Company
SONGS
San Onofre Nuclear Generating Station
SONGS OII
CPUC’s Order Instituting Investigation into the SONGS Outage
STIH
Sempra Texas Intermediate Holding Company LLC
Support Agreement
support
agreement, dated July 28, 2020, between Sempra Energy and Sumitomo Mitsui Banking Corporation
TAG JV
TAG Norte Holding, S. de R.L. de C.V.
Tangguh PSC
Tangguh PSC Contractors
TC Energy
TC Energy Corporation (formerly known as TransCanada Corporation)
7
GLOSSARY
(CONTINUED)
TCJA
Tax Cuts and Jobs Act of 2017
TdM
Termoeléctrica de Mexicali
TechnipFMC
TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of TechnipFMC plc
Tecnored
Tecnored S.A.
Tecsur
Tecsur S.A.
TO4
Electric
Transmission Owner Formula Rate, effective through December 31, 2018
TO5
Electric Transmission Owner Formula Rate, new application
TTHC
Texas Transmission Holdings Corporation
TTI
Texas Transmission Investment LLC
TURN
The Utility Reform Network
U.S. GAAP
accounting principles generally accepted in the United States of America
USMCA
United
States-Mexico-Canada Agreement
VaR
value at risk
VAT
value-added tax
Ventika
Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V., collectively
VIE
variable interest entity
Wildfire Fund
the fund established pursuant to AB 1054
Wildfire Legislation
AB 1054 and AB 111
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 the utilities in our Sempra Texas Utilities or Sempra Mexico segments or the utilities in our former South American businesses included in discontinued operations. All references in this report to our reportable segments are not intended to refer to any legal entity with the same or similar name.
Throughout this report, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:
▪the Consolidated Financial Statements and related Notes of Sempra
Energy and its subsidiaries and VIEs;
▪the Consolidated Financial Statements and related Notes of SDG&E and its VIE (until deconsolidation of the VIE in August 2019); and
▪the Financial Statements and related Notes of SoCalGas.
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INFORMATION
REGARDING FORWARD-LOOKING STATEMENTS
We make statements in this report that constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based on assumptions with respect to the future, involve risks and uncertainties, and are not guarantees. Future results may differ materially from those expressed in any forward-looking statements. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or other factors.
Forward-looking statements can be identified by words such as “believes,”“expects,”“anticipates,”“plans,”“estimates,”“projects,”“forecasts,”“should,”“could,”“would,”“will,”“confident,”“may,”“can,”“potential,”“possible,”“proposed,”“in process,”“under construction,”“in development,”“target,”“outlook,”“maintain,”“continue,” or similar expressions, or when we discuss our guidance, priorities, strategy, goals, vision, mission, opportunities, projections, intentions or expectations.
Factors, among others, that could cause actual results and events to differ materially from those described in any forward-looking statements include risks and uncertainties relating to:
▪California wildfires, including the risks that we may be found liable for damages regardless of fault and that we may not be able to recover costs from insurance, the Wildfire Fund or in rates from customers
▪decisions,
investigations, regulations, issuances or revocations of permits and other authorizations, renewals of franchises, and other actions by (i) the CFE, CPUC, DOE, PUCT, and other regulatory and governmental bodies and (ii) states, counties, cities and other jurisdictions in the U.S., Mexico and other countries in which we do business
▪the success of business development efforts, construction projects and major acquisitions and divestitures, including risks in (i) the ability to make a final investment decision, (ii) completing construction projects or other transactions on schedule and budget, (iii) the ability to realize anticipated benefits from any of these efforts if completed, and (iv) obtaining the consent of partners or other third parties
▪the resolution of civil and criminal litigation, regulatory inquiries, investigations
and proceedings, and arbitrations, including, among others, those related to the Leak
▪the impact of the COVID-19 pandemic on our capital projects, regulatory approval processes, supply chain, liquidity and execution of operations
▪actions by credit rating agencies to downgrade our credit ratings or to place those ratings on negative outlook and our ability to borrow on favorable terms and meet our substantial debt service obligations
▪moves to reduce or eliminate reliance on natural gas and the impact of volatility of oil prices on our businesses and development projects
▪weather, natural disasters, pandemics, accidents, equipment failures, explosions, acts of terrorism,
computer system outages and other events that disrupt our operations, damage our facilities and systems, cause the release of harmful materials, cause fires and subject us to liability for property damage or personal injuries, fines and penalties, some of which may not be covered by insurance (including costs in excess of applicable policy limits), may be disputed by insurers or may otherwise not be recoverable through regulatory mechanisms or may impact our ability to obtain satisfactory levels of affordable insurance
▪the availability of electric power and natural gas and natural gas storage capacity, including disruptions caused by failures in the transmission grid, limitations on the withdrawal of natural gas from storage facilities, and equipment failures
▪cybersecurity threats to the energy grid, storage and pipeline
infrastructure, the information and systems used to operate our businesses, and the confidentiality of our proprietary information and the personal information of our customers and employees
▪expropriation of assets, failure of foreign governments and state-owned entities to honor their contracts, and property disputes
▪the impact at SDG&E on competitive customer rates and reliability due to the growth in distributed and local power generation, including from departing retail load resulting from customers transferring to DA and CCA, and the risk of nonrecovery for stranded assets and contractual obligations
▪Oncor’s ability to eliminate or reduce its quarterly dividends due to regulatory and governance requirements and commitments, including
by actions of Oncor’s independent directors or a minority member director
▪volatility in foreign currency exchange and interest rates and commodity prices and our ability to effectively hedge these risks
▪changes in tax and trade policies, laws and regulations, including tariffs and revisions to international trade agreements that may increase our costs, reduce our competitiveness, or impair our ability to resolve trade disputes
▪other uncertainties, some of which may be difficult to predict and are beyond our control
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We caution you not to
rely unduly on any forward-looking statements. You should review and consider carefully the risks, uncertainties and other factors that affect our business as described herein and in other reports that we file with the SEC.
SUMMARY OF RISK FACTORS
There are a
number of risks that you should understand before making an investment decision in our securities or the securities of our subsidiaries. This summary is not intended to be complete and should only be read together with the information set forth in “Risk Factors” in this report. If any of these risks occur, Sempra Energy’s and its subsidiaries’ businesses, cash flows, financial condition, results of operations and/or prospects could be materially and adversely affected, and the trading prices of Sempra Energy’s securities and those of its subsidiaries could substantially decline. These risks include, among others, the following:
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 Cameron LNG JV.
▪The economic interest, voting rights and market value of our outstanding common and preferred stock may be adversely affected by any additional equity securities we may issue and, with respect to our common stock, by our outstanding preferred stock.
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 us.
▪The substantial debt service obligations of Sempra Energy, SDG&E and SoCalGas could have a material adverse effect on us, and with respect to Sempra Energy, could require additional
equity securities issuances.
▪The availability and cost of debt or equity financing could be adversely affected by conditions in the financial markets and economic conditions generally, as well as other factors, and any such negative effects could materially adversely affect us.
▪Certain credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook.
▪Our businesses are subject to complex governmental regulations and tax and accounting requirements and may be materially adversely affected by these regulations or requirements or any changes to them.
▪Our businesses require numerous permits, licenses, franchises, and other approvals and agreements
from various federal, state, local and foreign governmental agencies, and the failure to obtain or maintain any of them could materially adversely affect us.
Risks Related to the California Utilities
▪Wildfires in California pose a significant risk to the California Utilities (particularly SDG&E) and Sempra Energy.
▪The electricity industry is undergoing significant change, including increased deployment of distributed energy resources, technological advancements, and political and regulatory developments.
▪Natural gas and natural gas storage have increasingly been the subject of political and public scrutiny, including a desire by some to substantially reduce or eliminate reliance on natural gas as
an energy source.
▪The California Utilities are subject to extensive regulation by state, federal and local legislative and regulatory authorities, which may materially adversely affect us.
▪SoCalGas has incurred and may continue to incur significant costs, expenses and other liabilities related to the Leak, a substantial portion of which may not be recoverable through insurance.
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.
▪Changes in the electric utility industry, including changes in regulation
of ERCOT, could materially adversely affect Oncor, which could materially adversely affect us.
Risks Related to Our Businesses Other Than the California Utilities and Our Interest in Oncor
▪Project 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 us.
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▪Our businesses depend on the performance of counterparties, including with respect to long-term supply, sales and capacity agreements, and any failure by these parties to perform could result in
substantial expenses and business disruptions and exposure to commodity price risk and volatility, any of which could materially adversely affect us.
▪Our international businesses and operations expose us to legal, tax, economic, geopolitical, management oversight, foreign currency and inflation risks and challenges.
Risks Related to Our Proposed IEnova Exchange Offer and Our Proposed Transaction Related to Sempra Infrastructure Partners
▪Our ability to complete our proposed IEnova exchange offer is subject to various conditions and other risks and uncertainties that could cause the transaction to be abandoned, delayed or restructured, which could materially adversely affect us.
▪We expect to issue shares
of our common stock in the proposed exchange offer, which would dilute the voting interests and could dilute the economic interests of our current shareholders and may adversely affect the market value of our common stock and preferred stock.
▪The proposed exchange offer, if completed, would subject us to additional regulation and liability in Mexico.
▪Our proposed transaction related to Sempra Infrastructure Partners is subject to a number of risks and uncertainties.
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PART
I.
ITEM 1. BUSINESS
OVERVIEW
We are a California-based holding company
with energy infrastructure investments in North America. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers through regulated public utilities.
Sempra 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 80.25% interest in Oncor and 50% interest in Sharyland Utilities.
We have had a strong and growing presence in Mexico through IEnova. IEnova has a diverse portfolio of energy infrastructure projects and assets serving Mexico’s growing energy needs. Our energy infrastructure footprint includes our 50.2% interest in Cameron LNG JV, which is a natural gas
liquefaction export facility operating in Louisiana, and construction and development of LNG projects and assets on the Gulf Coast and Pacific Coast of North America.
In 2018, we announced a multi-phase portfolio optimization initiative designed to sharpen our strategic focus on North America. We have since executed on that initiative by completing the sales of our renewables businesses and our non-utility natural gas storage assets in the U.S., and by completing the sales of our businesses in South America. We present the South American businesses as discontinued operations throughout this report.
Business Strategy
Our mission is to be North America’s premier energy infrastructure company. We are primarily focused on transmission and distribution investments among other areas that we believe are capable of producing stable cash flows
and improved earnings visibility, with the goal of delivering safe and reliable energy to our customers and increasing shareholder value.
DESCRIPTION OF BUSINESS BY SEGMENT
Our business activities are organized under the following reportable segments:
▪SDG&E
▪SoCalGas
▪Sempra Texas Utilities
▪Sempra Mexico
▪Sempra LNG
SDG&E
SDG&E
is a regulated public utility that provides electric services to a population of, at December 31, 2020, 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 Orange County.
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SDG&E’s assets at December 31, 2020 covered the following territory:
Electric Utility Operations
Electric
Transmission and Distribution System. Service to SDG&E’s customers is supported by its electric transmission and distribution system, which includes substations and overhead and underground lines. These electric facilities are primarily in the San Diego, Imperial and Orange counties of California, and in Arizona and Nevada and consisted of 2,129 miles of transmission lines, 23,926 miles of distribution lines and 183 substations at December 31, 2020. Periodically, various areas of the service territory require expansion to accommodate customer growth and maintain reliability and safety.
SDG&E’s 500-kV Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,162 MW, although it can be
less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed and operated by SDG&E with import capability of 1,000 MW of power.
Mexico’s Baja California transmission system is connected to SDG&E’s system via two 230-kV interconnections with combined capacity of up to 600 MW in the north-to-south direction and 800 MW in the south-to-north direction, although it can be less under certain system conditions.
Edison’s transmission system is connected to SDG&E’s system via five 230-kV transmission lines.
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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 at December 31, 2020 was as follows:
SDG&E – ELECTRIC RESOURCES(1)
Contract
Net
operating
expiration date
capacity (MW)
% of total
Owned generation facilities, natural gas(2)
1,204
23
%
Purchased-power contracts:
Renewables:
Wind
2023
to 2035
1,131
22
Solar
2030 to 2041
1,326
26
Other
2022 and thereafter
203
4
Tolling and other
2022 to 2042
1,292
25
Total
5,156
100
%
(1)Excludes
approximately 107.5 MW of battery storage owned and approximately 174 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.
Charges under contracts with suppliers are based on the amount of energy received or are tolls based on available capacity. Tolling contracts are purchased-power contracts under which SDG&E provides natural gas for generation to the energy supplier.
SDG&E procures natural gas under short-term contracts for its owned generation facilities and for certain tolling contracts associated with purchased-power arrangements. Purchases are from various southwestern U.S. suppliers and are primarily priced based on published
monthly bid-week indices.
SDG&E is a participant in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers located throughout the U.S. and Canada. Participants can make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.
Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:
San Diego’s mild climate and SDG&E’s robust energy efficiency programs contribute to lower consumption by our customers. Rooftop solar installations continue to reduce residential and commercial volumes sold by SDG&E. At December 31, 2020, 2019 and 2018, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 1,423 MW, 1,233 MW and 1,023 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
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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 and CCA is only available if the customer’s local jurisdiction (city) offers such a program. Several local jurisdictions, including the City and County of San Diego and other municipalities, have implemented, are
implementing or are considering implementing CCA, which could result in SDG&E providing procurement service for less than half of its current customer load as early as December 31, 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 designed to equitably share costs among customers served by SDG&E and customers served by DA and CCA, 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.”
SoCalGas
SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission and storage system that supplies natural gas to a population of, at December 31, 2020, 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).
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SoCalGas’
assets at December 31, 2020 covered the following territory:
Natural Gas Utility Operations
We describe SoCalGas’ natural gas utility operations below in “California Utilities’ Natural Gas Utility Operations.”
California Utilities’ Natural Gas Utility Operations
Natural Gas Procurement and Transportation
At December 31, 2020, SoCalGas’
natural gas facilities included 3,059 miles of transmission and storage pipelines, 51,367 miles of distribution pipelines, 48,492 miles of service pipelines and nine transmission compressor stations, and SDG&E’s natural gas facilities consisted of 178 miles of transmission pipelines, 8,971 miles of distribution pipelines, 6,615 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 support 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 from outside of California and its transportation customers.
Natural Gas Storage
SoCalGas owns four natural gas storage facilities with a combined working gas capacity of 137 Bcf and over 150 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 to help maintain service reliability during peak demand periods, including consumer heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility has a storage capacity of 86 Bcf and, subject to the CPUC limitations described below, represents 63% of SoCalGas’ natural gas storage capacity. SoCalGas
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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 has been directed by the CPUC to maintain
up to 34 Bcf of working gas at the facility to help achieve reliability for the region at reasonable rates as determined by the CPUC. To help maintain system reliability, the CPUC issued a protocol authorizing withdrawals of natural gas from the facility if available gas supply and gas prices reach defined thresholds for SoCalGas’ system, as determined by the protocol. We discuss the Leak in Note 16 of the Notes to Consolidated Financial Statements, in “Part I – Item 1A. Risk Factors” and in “Part II – Item 7. MD&A – Capital Resources and Liquidity – SoCalGas.”
Customers and Demand
SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers in its territory and SDG&E’s territory on a combined portfolio basis. SoCalGas also offers natural gas transportation and storage services for others.
CALIFORNIA UTILITIES – NATURAL GAS CUSTOMER METERS AND VOLUMES
For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers.
Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase directly from producers, marketers or brokers, the California Utilities are obligated to provide reliable supplies of natural gas to serve the requirements of their core customers.
Noncore customers at SoCalGas consist primarily of electric generation, wholesale, and large commercial and industrial customers. A portion of SoCalGas’ noncore customers are non-end-users. SoCalGas’ non-end-users include wholesale customers consisting primarily of other utilities, including SDG&E,
or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial customers.
Noncore customers are responsible for the procurement of their natural gas requirements, as the regulatory framework does not allow us to recover the cost of natural gas procured and delivered to noncore customers.
Demand for natural gas largely depends on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs. Other external factors such as weather, the price of and demand for electricity, 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 outside
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California, and general economic conditions can also result in significant shifts in market price, which may in turn impact demand.
One of the larger sources for natural gas demand is electric generation. Natural gas-fired electric generation within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western U.S. Natural gas transported for electric generating plant customers may be affected by the overall demand for electricity, growth in self-generation from rooftop solar, the addition of more efficient gas technologies, new energy efficiency
initiatives, and the degree to which regulatory changes in electric transmission infrastructure investment divert electric generation from the California Utilities’ respective service areas. The demand for natural gas may also fluctuate due to volatility in the demand for electricity due to seasonality, weather conditions and other impacts, and the availability of competing supplies of electricity such as hydroelectric generation and other renewable energy sources. Given the significant quantity of natural gas-fired generation, we believe natural gas is a dispatchable fuel that can help provide electric reliability in our California service territories.
The natural gas distribution business is subject to seasonality, and cash provided by operating activities generally is greater during and immediately following the winter heating months. As is prevalent in the industry, but subject to current regulatory limitations, SoCalGas
usually injects natural gas into storage during the summer months (April through October), which reduces cash provided by operating activities during this period, and usually withdraws natural gas from storage during the winter months (November through March). Cash provided by operating activities during the winter months generally increases, when customer demand is higher.
Sempra Texas Utilities
Sempra Texas Utilities is comprised of our equity method investments in Oncor Holdings, which we acquired in March 2018, and Sharyland Holdings, which we acquired in May 2019. We discuss these acquisitions in Note 5 of the Notes to Consolidated Financial Statements. Oncor Holdings, which is an indirect, wholly owned entity of Sempra Energy, owns an 80.25% interest in Oncor.
TTI owns the remaining 19.75% interest in Oncor. Sempra Energy owns an indirect, 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities.
Sempra Texas Utilities’ assets at December 31, 2020 covered the following territory:
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Oncor
Oncor is a regulated electric transmission and distribution utility that operates in the north-central, eastern, western and panhandle regions of Texas. Oncor delivers electricity to end-use consumers through its transmission
and distribution systems, and also provides transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas.
At December 31, 2020, Oncor had 4,396 employees, including 767 employees under collective bargaining agreements.
Certain ring-fencing measures, governance mechanisms and commitments, which we describe in “Part I – Item 1A. Risk Factors,” are in effect and are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, their owners. Sempra Energy does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments limit our ability to direct the management,
policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions, including limited representation on the Oncor Holdings and Oncor boards of directors. Because Oncor Holdings and Oncor are managed independently (i.e., ring-fenced), we account for our 100% ownership interest in Oncor Holdings as an equity method investment. See Note 6 of the Notes to Consolidated Financial Statements for information about our equity method investment in Oncor Holdings.
Electricity Transmission.Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring,
controlling and dispatching of high-voltage electricity over its transmission facilities in coordination with ERCOT, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.”
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At December 31, 2020, Oncor’s transmission system included approximately 18,127 circuit miles of transmission lines, 336 transmission stations and 806 distribution substations, which are interconnected to 115 generation facilities totaling 41,986 MW.
Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to limited interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery
of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission business include system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.
Electricity Distribution. Oncor’s electricity distribution business is responsible for the overall safe and reliable operation of distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the electricity distribution system within its certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,660 distribution feeders.
Oncor’s
distribution system included more than 3.7 million points of delivery at December 31, 2020 and consisted of 121,129 miles of overhead and underground lines.
Distribution revenues from residential and small business users are based on actual monthly consumption (kWh) and distribution revenues from large commercial and industrial users are based on, depending on size and annual load factor, either actual monthly demand (kW) or the greater of actual monthly demand (kW) or 80% of peak monthly demand during the prior eleven months.
Customers and Demand. Oncor operates the largest transmission and distribution system in Texas. Oncor delivers electricity to more than 3.7 million homes and businesses in a territory with an estimated population in excess of 10 million and operates more than 139,000 miles of transmission
and distribution lines at December 31, 2020. The consumers of the electricity Oncor delivers are free to choose their electricity supplier from retail electric providers who compete for their business. Accordingly, Oncor is not a seller of electricity, nor does it purchase electricity for resale. Rather, Oncor provides transmission services to its electricity distribution business as well as non-affiliated electricity distribution companies, cooperatives and municipalities and distribution services to retail electric providers that sell electricity to retail customers. At December 31, 2020, Oncor’s distribution customers consisted of approximately 95 retail electric providers and certain electric cooperatives in its certificated service area.
Oncor’s transmission and distribution assets are located in over 120 counties and more
than 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, Waco, Wichita Falls, Odessa, Midland, Tyler, Temple, Killeen and Round Rock, among others. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law.
Oncor’s revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.
Competition. Oncor operates in certificated areas designated by the PUCT. The majority of Oncor’s service territory is single certificated, with Oncor as the only certificated electric transmission and distribution provider. However, in multi-certificated areas of Texas, Oncor competes with certain other utilities and rural electric cooperatives for
the right to serve end-use customers.
Sharyland Utilities
Sharyland Utilities is a regulated electric transmission utility that owns and operates, at December 31, 2020, approximately 63 miles of electric transmission lines in south Texas, including a direct current line connecting Mexico and assets in McAllen, Texas. Sharyland Utilities is responsible for providing safe, reliable and efficient transmission and substation services and investing to support infrastructure needs throughout the ERCOT grid, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.” Transmission revenues are provided under tariffs approved by the PUCT.
Sempra Mexico
Our
Sempra Mexico segment includes the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activities. IEnova develops, owns and operates, or holds interests in, energy infrastructure in Mexico in three key energy markets: gas, power and storage. IEnova’s gas business includes pipeline services for natural gas and ethane and associated or stand-alone compression assets, as well as its natural gas marketing business and natural gas distribution business. In its power business, IEnova operates a natural-gas-fired combined-cycle power plant and wind and solar power generation facilities, and is constructing and developing additional wind and solar power generation facilities. IEnova’s storage business includes refined products storage, its LPG storage and pipeline systems, and its ECA Regas Facility. Currently, IEnova is constructing and developing marine and land terminals for the receipt, storage and delivery of liquid fuels.
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Sempra Energy beneficially owned 70.2% of IEnova at December 31, 2020, with the remaining shares held by NCI and traded on the Mexican Stock Exchange under the symbol IENOVA. The CNBV regulates the shares, which are registered with the Mexican National Securities Registry (Registro Nacional de Valores) maintained by the CNBV. On December 2, 2020, we announced a non-binding offer to acquire all outstanding publicly held shares of IEnova in exchange for shares of our common stock at a rate of 0.0313 shares of our common stock for each one IEnova ordinary share, which exchange ratio remains subject to approval by the Sempra Energy board of directors and, if successful,
would increase Sempra Energy’s ownership interest in IEnova to 100% assuming that all IEnova public shareholders tender their shares. On December 1, 2020, we filed an application with the CNBV and on January 12, 2021, we filed a registration statement with the SEC, in each case in connection with the exchange offer. As part of the exchange offer, Sempra Energy intends to list its common stock on the Mexican Stock Exchange. We expect to complete this transaction in the second quarter of 2021, subject to authorization by the SEC, CNBV and Mexican Stock Exchange and other closing conditions. The proposed exchange offer is subject to a number of risks that are discussed in “Part I – Item 1A. Risk Factors.”
At December 31, 2020, Sempra Mexico’s assets covered the following territory:
Gas
Business
Pipelines and Related Assets. At December 31, 2020, IEnova’s pipeline and related assets consisted of 1,850 miles of natural gas transmission pipelines, 15 natural gas compression stations (two of which are under construction) and 139 miles of ethane pipelines in Mexico. These pipeline assets had design capacity of over 16,400 MMcf per day of natural gas, 204 MMcf per day of ethane gas and 106,000 barrels per day of ethane liquid. IEnova’s pipeline and related assets are contracted under long-term, U.S. dollar-based agreements with major industry participants such as the CFE, CENAGAS, PEMEX, Shell Mexico, Gazprom, Saavi Energía and other similar counterparties.
Natural Gas Distribution. IEnova’s natural gas distribution regulated utility, Ecogas, operates in three separate distribution
zones in Mexico with approximately 2,729 miles of pipeline, and had approximately 136,000 customer meters (serving more than 441,000 residential, commercial and industrial consumers) with sales volume of approximately eight MMcf per day in 2020.
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Ecogas relies on supply and transportation services from Sempra LNG and SoCalGas for the natural gas it distributes to its customers. If these affiliates fail to perform and Ecogas is unable to obtain supplies of natural gas from alternate sources, Ecogas could lose customers and sales volume and could also be exposed to commodity price risk and volatility.
Natural Gas Marketing. IEnova’s natural gas marketing business, IEnova Marketing, S. de R.L. de
C.V. (IEnova Marketing), purchases LNG for storage and regasification at the ECA Regas Facility and sells natural gas to affiliates and third-party customers. This business also purchases natural gas from Sempra Energy affiliates in order to sell it to IEnova customers in Baja California, including the CFE, which purchases such natural gas to power its plants in Rosarito, Baja California, and IEnova’s TdM combined-cycle power plant. IEnova Marketing also supplies natural gas purchased from Sempra Energy affiliates to third-party industrial customers in Mexicali, Chihuahua, Torreón and Durango. At December 31, 2020, IEnova Marketing served over 150 customers.
Power Business
Renewable Power Generation. IEnova develops, invests in and operates renewable energy generation facilities that have long-term PPAs to sell
the electricity they generate to their customers, which are generally load serving entities, as well as industrial and other customers. Load serving entities sell electric service to their end-users and wholesale customers upon receipt of power delivery from these energy generation facilities, while industrial and other customers consume the electricity to run their facilities. At December 31, 2020, IEnova had a fully contracted, total nameplate capacity of 1,041 MW related to its wind and solar power generation facilities that were either fully operating or under construction. Some of these facilities are impacted by regulatory actions by the Mexican government and related litigation, which we discuss in Note 16 of the Notes to Consolidated Financial Statements.
IENOVA
– RENEWABLE POWER GENERATION
Location
Contract expiration date
Nameplate capacity (MW)
Wind power generation facilities:
ESJ – first phase(1)
Tecate, Baja California
2035
155
ESJ
– second phase(1)(2)
Tecate, Baja California
2041
108
Ventika(3)
Nuevo León
2036
252
Solar power generation facilities:
Border(4)
Chihuahua
2032
and 2037
150
Don Diego
Sonora
2036 and 2037
125
Pima
Sonora
2039
110
Rumorosa
Baja California
2034
41
Tepezalá
Aguascalientes
2034
100
Total
1,041
(1) Includes
100% of the nameplate capacity, in which IEnova owns a 50% interest.
(2) We expect to start commercial operations in late 2021 or in the first quarter of 2022.
(3) Two adjacent wind power generation facilities.
(4) We expect to start commercial operations in the first half of 2021.
Natural Gas-Fired Generation. TdM is a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico that generates revenue from selling electricity and/or resource adequacy to the California ISO and to governmental, public utility and wholesale power marketing entities. It also has an EMA with Sempra LNG
for energy marketing, scheduling and other related services to support its sales of generated power into the California electricity market. Under the EMA, TdM pays fees to Sempra LNG for these revenue-generating services. TdM also purchases fuel from Sempra LNG. IEnova records revenue for the sale of power generated by TdM and records cost of sales for the purchases of natural gas and energy management services provided by Sempra LNG.
Storage Business
LNG Regasification. IEnova operates its ECA Regas Facility in Baja California, Mexico. The ECA Regas Facility is capable of processing one Bcf of natural gas per day and has a storage capacity of 320,000 cubic meters in two tanks of 160,000 cubic meters each. The facility generates revenues from reservation and usage fees under terminal capacity agreements and nitrogen injection service agreements with Shell Mexico
and Gazprom, expiring in 2028, that permit them, together, to use one-half of the terminal’s capacity. The land on which the ECA Regas Facility is situated is the subject of litigation, and Shell Mexico and Gazprom have commenced binding arbitration to terminate these agreements and seek other relief, both of which we discuss in Note 16 of the
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Notes to Consolidated Financial Statements, in “Part I – Item 1A. Risk Factors” and in “Part II – Item 7. MD&A – Capital Resources and Liquidity.”
Sempra LNG has an agreement with IEnova to supply LNG to the ECA Regas Facility. In connection with Sempra LNG’s purchase agreement with Tangguh PSC, IEnova purchases from Sempra LNG the LNG delivered by Tangguh PSC
to the ECA Regas Facility. IEnova uses the natural gas produced from this LNG and natural gas purchased in the market or through Sempra LNG’s marketing operations to supply a contract for the sale of natural gas to the CFE at prices that are based on the SoCal Border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, IEnova may purchase natural gas from Sempra LNG’s marketing operations.
Although the LNG purchase agreement with Tangguh PSC specifies a number of cargoes to be delivered annually, actual cargoes delivered have been significantly lower than the maximum specified under the agreement. As a result, Sempra LNG is contractually required to make monthly indemnity payments to IEnova for failure to deliver the contracted LNG.
IEnova entered into an agreement to assign its contracted capacity at the ECA Regas Facility to ECA
LNG Phase 1. Both parties will make use of the capacity through the expiration of the LNG purchase agreement with Tangguh PSC in 2029, and ECA LNG Phase 1 will be the sole user of this capacity thereafter.
LPG Storage and Associated Systems. IEnova owns and operates the TDF, S. de R. L. de C. V. (TDF) pipeline system and the Guadalajara LPG terminal. At December 31, 2020, the TDF pipeline system consisted of approximately 118 miles of a 12-inch diameter LPG pipeline with a design capacity of 34,000 barrels per day and associated storage and dispatch facilities. The TDF pipeline system runs from PEMEX’s Burgos facility in the state of Tamaulipas to IEnova’s delivery facility near the city of Monterrey, Nuevo León. IEnova’s Guadalajara LPG terminal is an 80,000-barrel LPG storage facility near Guadalajara, Jalisco, with associated loading and dispatch facilities,
and serves the LPG needs of Guadalajara, Mexico.
Refined Products Storage. IEnova’s refined products storage business develops systems for the receipt, storage and delivery of refined products, principally gasoline, diesel and jet fuel, throughout the states of Baja California, Colima, Puebla, Sinaloa, Veracruz, Valle de México and Jalisco for private companies. At December 31, 2020, IEnova had marine and inland terminals under development and construction, with a projected storage capacity of approximately 8,000,000 barrels, which may be expanded. We expect the inland terminals in the vicinity of Mexico City and Puebla and the Veracruz and Topolobampo marine terminals to reach commercial operations in various dates in 2021.
Demand and Competition
IEnova competes
with Mexican and foreign companies for certain new energy infrastructure projects in Mexico. Some of its competitors (including public or state-operated companies and their affiliates) may have better access to capital and greater financial and other resources, which could give them a competitive advantage in bidding for such projects.
Ecogas faces competition from other distributors of natural gas in each of its three distribution zones in Mexicali, Chihuahua and La Laguna-Durango as other distributors of natural gas build or consider building natural gas distribution systems. IEnova’s pipeline and storage facilities businesses compete with other regulated and unregulated pipeline and storage facilities. They compete primarily on the basis of price (in terms of storage and transportation fees), available capacity and interconnections to downstream markets.
The overall demand for
natural gas distribution services increases during the winter months, while the overall demand for power increases during the summer months.
Generation from IEnova’s renewable energy assets is susceptible to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight. Because IEnova sells power that it generates at its ESJ wind power generation facility into California, IEnova’s future performance and the demand for renewable energy may be impacted by U.S. state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements in California are generally known as the RPS Program. In California, certification of a generation project by the CEC as an ERR allows the purchase of output from such generation facility to be counted towards fulfillment of the RPS Program requirements, if such purchase meets the provisions of
SB X1-2, the California Renewable Energy Resources Act. The RPS Program may affect the demand for output from renewables projects developed by IEnova, particularly the demand from California’s utilities. We expect to pursue ERR certification for all our IEnova renewable facilities providing power to California as they become operational.
TdM competes daily with other generating plants that supply power into the California electricity market. Several of the wholesale markets supplied by merchant power plants have experienced significant pricing declines due to the imbalance between
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supply and demand. IEnova manages commodity price risk at TdM by using a mix of day ahead sales of energy, energy spreads hedging, ancillary
services, and short-term to medium-term capacity sales.
The LNG regasification business is impacted by worldwide LNG market prices. High LNG prices in markets outside the market in which IEnova’s ECA Regas Facility operates have resulted and could continue to result in lower than expected deliveries of LNG cargoes to the ECA Regas Facility, which could increase costs if IEnova is instead required to obtain LNG in the open market at prevailing prices. Any inability to obtain expected LNG cargoes could also impact IEnova’s ability to maintain the minimum level of LNG required to keep the ECA Regas Facility in operation at the proper temperature. Prices in international LNG markets through which IEnova must purchase natural gas to meet its contractual obligations to deliver natural gas to customers may also affect IEnova Marketing’s operations, which could have an adverse impact on its earnings, but may be mitigated in part by the indemnity
payments from Sempra LNG.
Sempra LNG
Sempra LNG develops, builds, operates and invests in natural gas liquefaction export facilities, including natural gas pipelines and infrastructure, and buys, sells and transports natural gas through its marketing operations, all within North America.
At December 31, 2020, Sempra LNG owned or held interests in the following assets:
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Natural
Gas Liquefaction
Cameron LNG JV. Sempra LNG and three project co-owners (TOTAL SE, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha) hold interests in Cameron LNG JV, which owns and operates a three-train natural gas liquefaction export facility (Phase 1) in Hackberry, Louisiana. Sempra LNG accounts for its 50.2% equity interest in Cameron LNG JV under the equity method.
Cameron LNG JV achieved commercial operations of Train 1, Train 2 and Train 3 in Phase 1 under its tolling agreements in August 2019, February 2020 and August 2020, respectively. The three liquefaction trains have a combined nameplate capacity of 13.9 Mtpa of LNG with an export capacity of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Cameron LNG JV has 20-year liquefaction and regasification tolling
capacity agreements in place with affiliates of TOTAL SE, Mitsubishi Corporation and Mitsui & Co., Ltd., which subscribe for the full nameplate capacity of the three trains at the facility. We discuss Cameron LNG JV in Note 6 of the Notes to Consolidated Financial Statements.
ECA LNG Phase 1. Sempra LNG, IEnova and an affiliate of TOTAL SE hold interests in ECA LNG Phase 1, which is constructing a one-train natural gas liquefaction facility at the site of IEnova’s existing ECA Regas Facility in Baja California, Mexico with a nameplate capacity of 3.25 Mtpa. We reached a final investment decision in November 2020. ECA LNG Phase 1 has a definitive 20-year LNG sale and purchase agreement with Mitsui & Co., Ltd. and an affiliate of TOTAL SE for approximately 0.8 Mtpa of LNG and 1.7 Mtpa of LNG, respectively.
Additional Potential LNG Export Projects.
Sempra LNG is evaluating the following additional potential LNG export development opportunities:
▪a natural gas liquefaction export project by ECA LNG Phase 2, also located at the site of IEnova’s existing ECA Regas Facility in Baja California, Mexico
▪a natural gas liquefaction export project (Port Arthur LNG) and associated infrastructure on a greenfield site in the vicinity of Port Arthur, Texas located along the Sabine-Neches waterway
We have not reached a final investment decision for any of these potential projects. The development of these projects is subject to numerous other risks and uncertainties. For a discussion of these
proposed projects and their risks, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra LNG.”
Midstream
Sempra LNG has a 40-mile natural gas pipeline in south Louisiana. The Cameron Interstate Pipeline links the Cameron LNG JV facility in Cameron Parish in Louisiana, to five interstate pipelines that offer access to major feed gas supply basins in Texas and the northeast, midcontinent and southeast regions of the U.S.
Marketing Operations
Sempra LNG provides natural gas marketing, trading and risk management services through the utilization and optimization of natural gas supply and transportation, including natural gas transport capacity in support of liquefaction projects in development. Additionally, it sells electricity
under short-term and long-term contracts and into the spot market and other competitive markets.
Sempra LNG’s marketing operations have an LNG sale and purchase agreement with Tangguh PSC for the supply of the equivalent of 500 MMcf of natural gas per day from Tangguh PSC’s Indonesian liquefaction facility with delivery to IEnova’s ECA Regas Facility at a price based on the SoCal Border index for natural gas. The LNG purchase agreement allows Tangguh PSC to divert certain LNG volumes to other global markets in exchange for cash differential payments to Sempra LNG. Sempra LNG may also enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the ECA Regas Facility for sale to other parties.
Sempra LNG is contracted to sell LNG or, if deliveries of LNG cargoes are not sufficient, natural gas, to Sempra Mexico that allows Sempra Mexico to satisfy
its obligation under supply agreements with the CFE, TdM and other customers. These revenues are adjusted for indemnity payments and profit sharing, as discussed in “Sempra Mexico – Storage Business – LNG Regasification” above.
Sempra LNG also has an EMA with Sempra Mexico’s TdM to provide energy marketing, scheduling and other related services to TdM power plant to support TdM’s sales of generated power into the California electricity market. We discuss the EMA in “Sempra Mexico – Power Business – Natural Gas-Fired Generation” above.
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Demand and Competition
North America is one of the most competitive locations for potential LNG supply in the world, resulting
from many factors, including:
▪high levels of developed and undeveloped North American unconventional natural gas and tight oil resources relative to domestic consumption levels
▪increasing gas and oil drilling productivity and decreasing unit costs of gas production
▪low breakeven prices of marginal North American unconventional gas production
▪proximity to ample existing gas transmission pipeline and underground gas storage capacity
Brownfield liquefaction is particularly competitive due to existing LNG tankage and berths.
Global LNG competition may limit North American LNG exports, as
international liquefaction projects attempt to match North American LNG production costs and customer contractual rights such as volume and destination flexibility. It is expected that North American LNG exports will increase competition for current and future global natural gas demand, and thereby facilitate development of a global commodity market for natural gas and LNG.
Additionally, our Cameron LNG JV co-owners and customers compete globally to market and sell LNG to end users, including gas and electric utilities located in LNG-importing countries around the world. By providing liquefaction services, Cameron LNG JV competes indirectly with liquefaction projects currently operating and those under development in the global LNG market. In addition to the U.S., these competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe.
Sempra
LNG’s pipeline business competes with other regulated and unregulated pipelines, primarily on the basis of price (in terms of transportation fees), available capacity and interconnections to downstream markets.
Discontinued Operations
In January 2019, our board of directors approved a plan to sell our South American businesses. These businesses included our former 100% interest in Chilquinta Energía (an electric distribution utility in Chile), our former 83.6% interest in Luz del Sur (an electric distribution utility in Peru) and our former interests in two energy-services companies, Tecnored and Tecsur, which provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, respectively, as well as third parties. These businesses and
certain activities associated with these businesses are presented as discontinued operations in this report. We completed the sales of our equity interests in our Peruvian businesses in April 2020 and our Chilean businesses in June 2020.
We provide further information about discontinued operations in Note 5 of the Notes to Consolidated Financial Statements.
REGULATION
We discuss the material effects of compliance with all government regulations, including environmental regulations, on our capital expenditures, earnings and competitive position in “Part II – Item 7. MD&A” and Note 16 of the Notes to Consolidated Financial Statements.
Utility
Regulation
California
The California Utilities are principally regulated at the state level by the CPUC, CEC and CARB.
The CPUC:
▪consists of five commissioners appointed by the Governor of California for staggered, six-year terms;
▪regulates, among other things, SDG&E’s and SoCalGas’ customer rates and conditions of service, sales of securities, rates of return, capital structure, rates of depreciation, and long-term resource procurement, except as described below in “U.S. Federal;”
▪has jurisdiction over the proposed construction of major new electric generation, transmission and distribution, and natural
gas storage, transmission and distribution facilities in California;
▪conducts reviews and audits of utility performance and compliance with regulatory guidelines and conducts investigations related to various matters, such as safety, reliability and planning, deregulation, competition and the environment; and
▪regulates the interactions and transactions of the California Utilities with Sempra Energy and its other affiliates.
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The CPUC also oversees and regulates other energy-related products and services, including solar and wind energy, bioenergy, alternative energy storage and other forms of renewable energy.
In addition, the CPUC’s safety and enforcement role includes inspections, investigations and penalty and citation processes for safety and other violations.
The CEC publishes electric demand forecasts for the state and for specific service territories. Based on these forecasts, the CEC:
▪determines the need for additional energy sources and conservation programs;
▪sponsors alternative-energy research and development projects;
▪promotes energy conservation programs to reduce demand for natural gas and electricity within California;
▪maintains a statewide plan of action in case of energy shortages; and
▪certifies
power-plant sites and related facilities within California.
The CEC conducts a 20-year forecast of available supplies and prices for every market sector that consumes natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and costs of transportation and distribution. This analysis is one of many resource materials used to support the California Utilities’ long-term investment decisions.
California requires certain of its electric retail sellers, including SDG&E, to deliver a significant percentage of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by both the CPUC and the CEC, are generally known as the RPS Program.
AB 32, the California Global Warming Solutions Act of 2006, assigns responsibility
to CARB for monitoring and establishing policies for reducing GHG emissions. The law requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable and cost-effective GHG emissions reductions, including a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a department within the California Environmental Protection Agency, an organization that reports directly to the Governor’s Office. Sempra LNG and Sempra Mexico are also subject to the rules and regulations of CARB.
The operation and maintenance of SoCalGas’ natural gas storage facilities are regulated by CalGEM, as well as various other state and local agencies.
Texas
Oncor’s and Sharyland Utilities’ rates are regulated at the state level by the PUCT and, in the case of
Oncor, at the city level by certain cities. The PUCT has original jurisdiction over electric transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT, and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, the Texas PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that do not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).
At the state level, PURA requires owners or operators of electric transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing
the state open-access requirements for all utilities that are subject to the PUCT’s jurisdiction over electric transmission services, including Oncor.
U.S. Federal
The California Utilities are also regulated at the federal level by the FERC, the NRC, the EPA, the DOE and the DOT.
The FERC regulates the California Utilities’ interstate sale and transportation of natural gas. In the case of SDG&E, the FERC also regulates the transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return on transmission investment, rates of depreciation, electric rates involving sales for resale and the application of the uniform system of accounts. The U.S. Energy Policy Act governs procedures for requests for electric transmission service. The California IOUs’ electric transmission facilities are under the
operational control of the California ISO. Oncor and Sharyland Utilities operate within the ERCOT market, which we discuss below. To a small degree related to limited interconnections to other markets, Oncor’s electric transmission revenues are provided under tariffs approved by the FERC.
The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities in the U.S., including SONGS, in which SDG&E owns a 20% interest and which was permanently retired in 2013. NRC and various state regulations require extensive review of the safety, radiological and environmental aspects of these facilities. We provide further discussion of SONGS matters, including the closure and decommissioning of the facility, in Note 15 of the Notes to Consolidated Financial Statements.
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The
EPA implements federal laws to protect human health and the environment, including federal laws on air quality, water quality, wastewater discharge, solid waste management, and hazardous waste disposal and remediation. The EPA also sets national environmental standards that state and tribal governments implement through their own regulations. The California Utilities, Oncor and Sharyland Utilities are therefore subject to an interrelated framework of environmental laws and regulations.
The DOT, through PHMSA, has established regulations regarding engineering standards and operating procedures applicable to the California Utilities’ natural gas transmission and distribution pipelines, as well as natural gas storage facilities. The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities they regulate in California.
ERCOT Market
Oncor
and Sharyland Utilities operate within the ERCOT market, which represents approximately 90% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the ISO of the interconnected transmission grid for those systems. ERCOT is subject to oversight by the PUCT and the Texas Legislature. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants, in the ERCOT region. ERCOT’s membership consists of corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers, distribution services providers, independent retail electric providers and consumers.
The PUCT has primary jurisdiction over the ERCOT market
to ensure the adequacy and reliability of power supply across Texas’ main interconnected electric transmission grid. Oncor and Sharyland Utilities, along with other owners of electric transmission and distribution facilities in Texas, assist the ERCOT ISO in its operations. Each of these Texas utilities has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Each participates with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove any existing constraints and interconnect energy generation on the ERCOT transmission grid. These transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.
Oncor
and Sharyland Utilities are subject to reliability standards adopted and enforced by the Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with the standards of the North American Electric Reliability Corporation, including critical infrastructure protection, and ERCOT protocols.
Other U.S. State and Local Territories Regulation
The SCAQMD is the air pollution control agency responsible for regulating stationary sources of air pollution in the South Coast Air Basin in Southern California. The district’s territory covers all of Orange County and the urban portions of Los Angeles, San Bernardino and Riverside counties.
SDG&E has electric franchises with the two counties and the 27 cities in or adjoining its electric service territory,
and natural gas franchises with the one county and the 18 cities in its natural gas service territory. These franchises allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of natural gas and/or electricity. Most of the franchises have indefinite lives with no expiration dates. Some of SDG&E’s natural gas and electric franchises have fixed expiration dates that range from 2021 to 2035, including its franchise agreements with the City of San Diego, which was scheduled to expire in January 2021. SDG&E participated in the City’s competitive bid process for the franchises, which the City subsequently canceled. In December 2020, the City of San Diego and SDG&E agreed to extend the natural gas and electric franchises until June 1, 2021. The extension is intended to provide newly elected City officials time to seek public input and additional information. The City has announced
its plans to start a new competitive bid process in the first quarter of 2021.
SoCalGas has natural gas franchises with the 12 counties and the 223 cities in its service territory. These franchises allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the franchises have indefinite lives with no expiration date. Some franchises have fixed expiration dates, ranging from 2021 to 2069, including its franchise agreements with the City of Los Angeles and Los Angeles County, which are scheduled to expire in December 2021 and June 2023, respectively.
Other U.S. Regulation
The FERC regulates certain Sempra LNG assets pursuant to the U.S. Federal Power Act and Natural Gas Act, which provide for FERC jurisdiction over, among other things, sales of wholesale power in interstate commerce,
transportation of natural gas in interstate commerce, and siting and permitting of LNG facilities.
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The FERC may regulate rates and terms of service based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be sufficiently competitive, rates may be market-based. FERC-regulated rates at Sempra LNG are:
▪market-based for wholesale electricity sales;
▪cost-based for the transportation of natural gas; and
▪market-based for the purchase and sale of LNG and natural gas.
Sempra
LNG’s investment in Cameron LNG JV is subject to regulations of the DOE regarding the export of LNG. Sempra LNG’s other potential natural gas liquefaction export projects would, if completed, be subject to similar regulation.
The California Utilities, Sempra LNG and businesses that Sempra LNG invests in are subject to the DOT rules and regulations regarding pipeline safety. PHMSA, acting through the Office of Pipeline Safety, is responsible for administering the DOT’s national regulatory program to help ensure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines, including pipelines associated with natural gas storage, and develops regulations and other approaches to risk management to help ensure safety in design, construction, testing, operation, maintenance and emergency response of pipeline facilities. The California Utilities, Sempra LNG and Sempra Mexico are also subject to regulation
by the U.S. Commodity Futures Trading Commission.
Foreign Regulation
Operations and projects in our Sempra Mexico segment are subject to regulation by the CRE, the Mexican Safety, Energy and Environment Agency (Agencia de Seguridad, Energía y Ambiente), SENER, the Mexican Ministry of Environment and Natural Resources of Mexico (Secretaría del Medio Ambiente y Recursos Naturales), and other labor and environmental agencies of city, state and federal governments in Mexico. New energy infrastructure projects may also require a favorable opinion from COFECE in order to be constructed and operated.
Licenses and Permits
Our utilities in California and Texas obtain numerous permits, authorizations and licenses for, as applicable, the transmission and distribution of natural gas and electricity and the
operation and construction of related assets, including electric generation and natural gas storage facilities, some of which may require periodic renewal.
Sempra Mexico obtains numerous permits, authorizations and licenses for its electric and natural gas distribution, generation and transmission systems from the local governments where these services are provided. The permits for generation, transportation, storage and distribution operations at Sempra Mexico are generally for 30-year terms, with options for renewal under certain regulatory conditions.
Sempra Mexico and Sempra LNG obtain licenses and permits for the construction, operation and expansion of LNG facilities and for the import and export of LNG and natural gas. Sempra Mexico also obtains licenses and permits for the construction and operation of facilities for the receipt, storage and delivery of liquid fuels.
Sempra
LNG obtains permits, authorizations and licenses for the construction and operation of natural gas storage facilities and pipelines, and in connection with participation in the wholesale electricity market.
Most of the permits and licenses associated with Sempra LNG’s construction and operations are for periods generally in alignment with the construction cycle or expected useful life of the asset and in many cases are greater than 20 years.
RATEMAKING MECHANISMS
California Utilities
General Rate Case Proceedings
A CPUC GRC proceeding is designed to set sufficient base rates to allow the California Utilities to recover their reasonable forecasted operating costs and to provide the opportunity to realize their authorized rates of return on their investment.
The proceeding generally establishes the test year revenue requirements, which authorizes how much the California Utilities can collect from their customers, and provides for attrition, or annual increases in revenue requirements, for each year following the test year.
We discuss the GRC in Note 4 of the Notes to Consolidated Financial Statements.
Cost of Capital Proceedings
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A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized return on rate base, which is a weighted-average of the authorized returns on debt, preferred stock and common equity (referred to as return on equity or ROE), weighted on a basis consistent with the
authorized capital structure. The authorized return on rate base approved by the CPUC is the rate that the California Utilities use to establish customer rates to finance investments in CPUC-regulated electric distribution and generation, natural gas distribution, transmission and storage assets, as well as general plant and information technology systems investments to support operations.
A cost of capital proceeding also addresses the CCM, which considers changes in interest rates based on the applicable 12-month average Moody’s utility bond index. The index applicable to each utility is based on each utility’s credit rating. The CCM was reauthorized in the 2020 cost of capital proceeding and will continue through 2022, after which the CCM is subject to reauthorization in the next cost of capital proceeding. The CCM benchmark rates for SDG&E and SoCalGas are the basis of comparison to determine if future measurement periods
“trigger” the CCM. The trigger occurs if the change in the applicable average Moody’s utility bond index relative to the CCM benchmark is larger than plus or minus 100 bps. The CCM, if triggered, would automatically update the authorized cost of debt based on actual costs and update the authorized ROE upward or downward by one-half of the difference between the CCM benchmark and the applicable 12-month average Moody’s utility bond index. In the event of a CCM trigger in 2021, the CCM benchmark is also reestablished, and these adjustments would become effective in authorized rates on January 1, 2022.
We discuss the cost of capital and CCM in Note 4 of the Notes to Consolidated Financial Statements and in “Part I – Item 1A. Risk Factors.”
Transmission Rate Cases
SDG&E
files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets. The proceeding establishes a ROE and a formulaic rate whereby rates are determined using (1) a base period of historical costs and a forecast of capital investments, and (2) a true-up period, similar to balancing account treatment, that is designed to provide earnings equal to SDG&E’s actual cost of service including its authorized return on investment. SDG&E makes annual information filings with the FERC in December to update rates for the following calendar year. SDG&E may also file for ROE incentives that might apply under FERC rules. SDG&E’s debt-to-equity ratio is set annually based on the actual ratio at the end of each year.
We discuss SDG&E’s TO5 filing with the FERC in Note 4 of the Notes to Consolidated Financial Statements.
Incentive
Mechanisms
The CPUC applies certain performance-based measures and incentive mechanisms to all California IOUs, under which the California Utilities have earnings potential above authorized CPUC base operating margin 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.
Other Cost-Based Recovery
The CPUC, and the FERC as it relates to SDG&E, authorize the California Utilities to collect revenue requirements from customers for operating costs and capital related costs (such as depreciation, taxes and return on rate base), including:
▪costs to purchase
natural gas and electricity;
▪costs associated with administering public purpose, demand response, and customer energy efficiency programs;
▪other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and
▪costs associated with third-party liability insurance premiums.
Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded within a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met
at the time the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund for programs authorized, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers.
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Sempra Texas Utilities
Rates and Cost Recovery
Oncor’s and Sharyland Utilities’ rates are each regulated at the state level by the PUCT and, in the case of Oncor, at
the city level by certain cities, and are subject to regulatory rate-setting processes and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Instead, their rates are regulated based on an analysis of each utility’s costs and capital structure, as reviewed and approved in regulatory proceedings. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. However, there is no assurance that the PUCT will judge all of the Texas utilities’ costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure upon which the Texas utilities’ rates are based, that the regulatory process in which rates are determined will necessarily result in rates that produce full recovery of the Texas utilities’ costs or that their authorized ROE will not be reduced.
The
PURA allows Texas electric utilities providing wholesale or retail distribution service to file, under certain circumstances, once per year and up to four rate adjustments between comprehensive base rate proceedings to recover distribution-related investments on an interim basis. The PUCT’s substantive rules also allow the Texas utilities to update their transmission rates periodically on an interim basis to reflect changes in invested capital. These “capital tracker” provisions are intended to encourage investment in the electric system to help ensure reliability and efficiency by allowing for timely recovery of and return on new investments.
Capital Structure and Return on Equity
Oncor has a PUCT-authorized ROE of 9.8% and an authorized regulatory capital structure of 57.5% debt to 42.5% equity. Sharyland Utilities’ PUCT-authorized ROE is 9.7% and its authorized regulatory
capital structure is 55% debt to 45% equity. Sharyland Utilities filed its 2020 rate case with the PUCT in December 2020. Oncor is required to file a base rate review on or before October 1, 2021.
Sempra Mexico
Ecogas’ revenues are derived from service and distribution fees charged to its customers in Mexican pesos. The price Ecogas pays to purchase natural gas, which is based on international price indices, is passed through directly to its customers. The service and distribution fees charged by Ecogas are regulated by the CRE, which performs a review of rates every five years and monitors prices charged to end-users. In the fourth quarter of 2020, Ecogas filed its rate case for the period 2021 through 2025. Ecogas expects to receive a decision in 2021. The tariffs operate under a return-on-asset-base model. In the annual tariff
adjustment, rates are adjusted to account for inflation or fluctuations in exchange rates, and inflation indexing includes separate U.S. and Mexican cost components so that U.S. costs can be included in the final distribution rates.
ENVIRONMENTAL MATTERS
We discuss environmental issues affecting us in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.” You should read the following additional information in conjunction with those discussions.
Hazardous Substances
The CPUC’s Hazardous Waste Collaborative mechanism allows California’s IOUs to recover hazardous waste cleanup costs for certain
sites, including those related to certain Superfund sites. This mechanism permits the California Utilities to recover in rates 90% of hazardous waste cleanup costs and related third-party litigation costs, and 70% of related insurance-litigation expenses. In addition, the California Utilities have the opportunity to retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates.
We record estimated liabilities for environmental remediation when amounts are probable and estimable. In addition, we record amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism as regulatory assets.
Air and Water Quality
The natural gas and electric industries are subject to increasingly stringent air quality and GHG emissions
standards, such as those established by CARB and SCAQMD. The California Utilities generally recover in rates the costs to comply with these standards. We discuss GHG emissions standards and credits further in Note 1 of the Notes to Consolidated Financial Statements.
We discuss environmental matters concerning the Leak in Note 16 of the Notes to Consolidated Financial Statements and in “Part I – Item 1A. Risk Factors.”
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OTHER MATTERS
Information About Our Executive Officers
INFORMATION
ABOUT EXECUTIVE OFFICERS AT SEMPRA ENERGY
Name
Age(1)
Positions held over last five years
Time in position
Jeffrey W. Martin
59
Chairman
December 2018 to present
Chief Executive Officer
May
2018 to present
President
March 2020 to present
Executive Vice President and Chief Financial Officer
Our ability to advance our mission to be North America’s premier energy infrastructure company largely depends on the safety, engagement, and responsible actions of our employees.
Safety is foundational at Sempra Energy and its subsidiaries. We strive to foster a strong safety culture and reinforce this culture through training programs, benchmarking, review and analysis of safety trends, and sharing lessons learned from safety incidents across our businesses. Our businesses also engage in safety-related scenario planning and simulation, develop and implement operational contingency plans, and review safety plans and procedures with work crews regularly. We also participate in emergency planning
and preparedness in the communities we serve and train critical employees in emergency management and response each year. The Safety, Sustainability and Technology committee of the Sempra Energy board of directors assists the board in overseeing the corporation’s oversight programs and performance related to safety.
Our culture is another important aspect of our ability to advance our mission. We embrace diversity in our workforce and strive to create a high-performing, inclusive and supportive workplace where employees of all backgrounds and experiences can feel valued and respected. We invest in recruiting, developing and retaining high-potential employees who represent the communities we serve, and we provide a range of programs to advance those objectives, including internal and external mentoring and leadership training, workshops and a tuition reimbursement program. We also invest in internal communications programs,
including in-person and virtual learning and networking opportunities as well as regular executive communications. In addition, we offer a variety of in-person and virtual employee community service opportunities and, at our U.S. operations, we support employees’ personal volunteering and charitable giving through Sempra Energy’s charitable matching program. Employees participate in annual ethics and compliance training each year, which includes a review of Sempra Energy’s Code of Conduct as well as resources such as the Sempra Energy’s ethics and compliance hotline. We measure culture and employee engagement
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through a variety of channels including pulse surveys, suggestion boxes and a biannual engagement survey administered by a third party. Sempra Energy’s
board of directors is chartered with overseeing our culture.
The table below shows the number of employees for each of our registrants at December 31, 2020, as well as the percentage of those employees represented by labor unions under various collective bargaining agreements that generally cover wages, benefits, working conditions and other terms and conditions of employment. We did not experience any major work stoppages in 2020 and we maintain constructive relations with our labor unions.
NUMBER
OF EMPLOYEES
Number of employees
% of employees covered under collective bargaining agreements
% of employees covered under collective bargaining agreements expiring within one year
Sempra Energy Consolidated(1)
14,706
41
%
32
%
SDG&E
4,595
29
%
—
%
SoCalGas
7,851
59
%
59
%
(1) Excludes
employees of equity method investees.
We
make available free of charge on the Sempra Energy website, and for SDG&E and SoCalGas, via a hyperlink on their websites, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.
The references to our websites are not active hyperlinks and the information contained on, or that can be accessed through, the websites of Sempra Energy, SDG&E and SoCalGas is not part of this report or any other report that we file with or furnish to the SEC and is not incorporated herein by reference.
ITEM
1A. RISK FACTORS
When evaluating our company and its subsidiaries and any investment in our or their securities, you should consider carefully the following risk factors and all other information contained in this report and in the other documents we file with the SEC, including in documents we file subsequent to 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 these risks occurs, our businesses, cash flows, results of operations, financial condition and/or prospects could be materially adversely affected, and the trading prices of our securities and those of our subsidiaries could substantially decline. These risk factors should
be read in conjunction with the other information concerning our company set forth in or attached as an exhibit to this report, including, among other things, the information set forth in the Consolidated Financial Statements and in “Part II – Item 7. MD&A.”
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Risks Related to Sempra Energy
Operational and Structural Risks
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 Cameron LNG JV.
We are a holding company and substantially
all our assets are owned by our subsidiaries or entities we do not control, which include equity method investments such as Oncor Holdings and Cameron LNG JV. Our ability to pay dividends and to meet our debt and other obligations largely depends on cash flows from our subsidiaries and equity method investments. Cash flows from our subsidiaries and equity method investments depend on their ability to successfully execute their business strategies and generate cash flows in excess of their own expenditures, common and preferred dividends (if any), and debt and other obligations. In addition, the entities accounted for as equity method investments, which we do not control, and our subsidiaries are all separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be precluded from paying any such dividends or making any such loans or distributions under certain circumstances, including, among other things, as
a result of legislation, regulation, court order or contractual restrictions or in times of financial distress. The inability to access capital from our subsidiaries and entities accounted for as equity method investments could have a material adverse effect on our cash flows, financial condition and/or prospects.
Sempra Energy’s rights to the assets of its subsidiaries and equity method investments are structurally subordinated to the claims of that entity’s creditors, including trade creditors. In addition, to the extent Sempra Energy is a creditor of any such entity, its rights as a creditor would be effectively subordinated to any security interest in the assets of that entity and any indebtedness of the entity senior to that held by Sempra Energy.
Sempra Energy has substantial investments in and obligations arising from businesses that it does not control or manage or in which
it shares control.
We have and make investments in entities that we do not control or manage or in which we share control, which include Sempra Energy’s direct or indirect interest in Oncor, Cameron LNG JV and RBS Sempra Commodities; SDG&E’s interest in SONGS; and IEnova’s indirect interest in the Sur de Texas-Tuxpan natural gas marine pipeline in Mexico, among others. In some cases, we engage in other arrangements with or for these entities that could expose us to risks in addition to our investment. For example, Sempra Energy has provided guarantees in support of financing agreements related to Cameron LNG JV, Sempra Energy is subject to certain indemnities with respect to RBS Sempra Commodities, and Sempra Mexico has provided loans to JVs in which it has investments. We discuss the guarantees in Note 6, indemnities in Note 16, and affiliate loans in Note 1 of the Notes to Consolidated Financial Statements.
Where
we share control with other equity owners, any disagreements among the owners of these businesses with respect to material issues, including strategy, financial, operational or transactional matters, could have a material adverse effect on the ability of that business to move forward with key initiatives or projects or take other actions, and could also negatively affect the long-term relationships among the business owners and the ability of the entity to function efficiently and effectively. Any such circumstance could materially adversely affect our business, financial condition, cash flows, result of operations and/or prospects.
With respect to ventures and other businesses over which we do not exercise control, we could be responsible for significant liabilities or losses related to these businesses, such as our investment in RBS Sempra Commodities where we recorded $100 million in equity losses representing our estimated
obligations to settle outstanding tax matters and related legal costs, and where we could be subject to further losses upon final resolution of these matters. In addition to other risks inherent in these businesses, if their management were to fail to perform adequately, the other investors in the businesses were unable or otherwise failed to perform their obligations to provide capital and credit support for these businesses, business decisions were made with which we do not agree or other factors were to result in liabilities or losses at these entities, 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 16 of the Notes to Consolidated Financial Statements.
Our business could be negatively affected as a result of actions of activist shareholders.
Activist shareholders
may, from time to time, engage in proxy solicitations, advance shareholder proposals, or otherwise attempt to effect changes and assert influence on our board of directors and management. In taking these steps, activist shareholders could seek to acquire significant amounts of our capital stock, which could threaten our ability to use some or all our NOL carryforwards if any such attempt were to result in our corporation undergoing an “ownership change” under applicable tax rules. Responding to activist shareholders would require us to incur significant legal and advisory fees, proxy solicitation expenses (in
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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 the composition of our board of directors or senior management team arising from a proxy contest or increased ownership or other interest in our company from activist shareholders could lead to the perception of a change in the direction of our business or instability, which could be exploited by our competitors and/or other activist shareholders, result in the loss of business opportunities, and make it more difficult to pursue our strategic initiatives or attract and retain qualified personnel and business partners, any of which could have a material adverse effect on our business, operating results and/or prospects. Further, any such actions could cause significant fluctuations in the trading prices of our common stock, preferred stock and debt
securities based on temporary or speculative market perceptions or other factors that may not reflect the underlying fundamentals and prospects of our business.
Financial and Capital Stock-Related Risks
Any impairment of our assets could negatively impact our consolidated results of operations and net worth.
We could experience a reduction in the fair value of our assets, including our long-lived assets, intangible assets or goodwill, upon the occurrence of many of the risks discussed in these risk factors. Any such reduction in the fair value of our assets could result in an impairment loss that could materially adversely affect our results of operations for the period in which such charge is recorded. We discuss our impairment testing of long-lived assets and goodwill and the factors considered in such testing in “Part II – Item 7.
MD&A – Critical Accounting Policies and Estimates” and in Note 1 of the Notes to Consolidated Financial Statements.
The economic interest, voting rights and market value of our outstanding common and preferred stock may be adversely affected by any additional equity securities we may issue and, with respect to our common stock, by our outstanding preferred stock.
At February 25, 2021, we have 6,650,000 shares of preferred stock outstanding, 5,750,000 of which constitute our series B preferred stock and are scheduled to convert into shares of our common stock on July 15, 2021, and the remaining 900,000 of which constitute our series C preferred stock and are not convertible. We also issued 13,781,025 shares of our common stock on January
15, 2021 upon the mandatory conversion of our former series A preferred stock in accordance with the terms of those securities. We may seek to raise capital by issuing additional shares of common or preferred stock, which, together with the conversion of the series B preferred stock into our common stock, may materially dilute the voting rights and economic interests of holders of our outstanding common and preferred stock and materially adversely affect the trading price of our common and preferred stock.
Dividend requirements associated with our preferred stock subject us to certain risks.
Any future cash dividends we pay on our series B preferred stock and series C preferred stock will depend on, among other things, our financial condition, capital requirements and results of operations, the ability of our subsidiaries and equity method investees to distribute cash to us,
and other factors that our board of directors may consider relevant. Any failure to pay scheduled dividends on our preferred stock when due would have a material adverse impact on the market price of our preferred stock, our common stock and our debt securities and would prohibit us, under the terms of our 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 preferred stock.
The terms of the series B preferred stock and series C preferred stock generally provide that if dividends on any shares of the preferred stock have not been declared and paid or have been declared but not paid for six or more quarterly dividend periods for the series B preferred stock and three or more semi-annual dividend periods for the series C preferred stock, whether or not for consecutive dividend periods,
the holders of the preferred stock, voting together as a single class, will be entitled to elect a total of two additional members to our board of directors, subject to certain terms and limitations.
Risks Related to All Sempra Energy Businesses
Operational Risks
Our businesses face risks related to the COVID-19 pandemic.
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The COVID-19 pandemic is materially impacting communities, supply chains and markets around the world. The U.S. economy is experiencing a significant slowdown and claims for unemployment have substantially increased. To date, the COVID-19 pandemic has not had a material impact on our results of operations. However,
we are conducting business with substantial modifications to employee travel, employee work locations, and virtualization or cancellation of certain business activities, among other modifications. If these or other similar measures were to increase or continue for an extended period, we could experience employee absenteeism, decreased efficiency and productivity by our workforce and other similar impacts that could jeopardize our ability to sustain operations and satisfy compliance requirements and could result in higher operating costs. We also have observed other companies, including our current and prospective counterparties, customers and partners, as well as many governments, including our regulators and other governing bodies that affect our businesses, taking precautionary, preemptive and responsive actions to address the effects of the COVID-19 pandemic, and they may take further actions that alter their normal operations. These actions by third parties could
materially impact our operations, results, liquidity and ability to pursue capital projects and strategic initiatives. For example, the CPUC has required that all energy companies under its jurisdiction take action to implement several emergency customer protection measures to support California customers. The measures currently apply to all residential and small business customers affected by the COVID-19 pandemic and include suspending service disconnections due to nonpayment, waiving late payment fees, and offering flexible payment plans to customers experiencing difficulty paying their electric or gas bills. These actions have resulted in a reduction in payments received from our customers and an increase in uncollectible accounts, which could become material, and any inability or delay in recovering all or a substantial portion of these costs could have a material adverse effect on the cash flows, financial condition and results of operations for Sempra Energy,
SDG&E and SoCalGas. As an additional example, we reached a final investment decision with respect to ECA LNG Phase 1 in November 2020, the timing of which was delayed in part by the COVID-19 pandemic. If this or other projects under development are further delayed due to continuing or worsening conditions caused by the COVID-19 pandemic or other related factors, the performance and prospects of our LNG export business could be materially adversely affected.
Although Sempra Energy, SDG&E and SoCalGas are not currently constrained in their ability to borrow money at reasonable rates, these circumstances could change if the COVID-19 pandemic worsens or continues for an extended period and adversely affects conditions in the capital markets, which could have a material negative effect on our liquidity, results of operations, strategic initiatives and prospects. The COVID-19 pandemic could result in an increased slowdown
of certain of our capital spending if conditions deteriorate or fail to improve in the near term, which could have a material adverse effect on Sempra Energy’s, SDG&E’s and SoCalGas’ results of operations and prospects.
We will continue to actively monitor the effects of the COVID-19 pandemic and may take further actions that alter our business operations as may be required by federal, state or local authorities, or that we determine are in the best interests of our employees, customers, partners and suppliers. However, we cannot at this time predict the extent to which the COVID-19 pandemic will further impact our liquidity, financial condition, results of operations and prospects.
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 capital intensive businesses, our facilities and infrastructure may be damaged by severe weather conditions and natural disasters such as fires, earthquakes, tornadoes, hurricanes, other storms, tsunamis, heat waves, rising sea levels, floods, mudslides, drought, solar events and electromagnetic events; pandemics; accidents; equipment failures; explosions; or acts of terrorism, vandalism, war or criminality. 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 for which we could be held responsible, 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, among others:
▪natural gas, propane and ethane pipelines, storage and compressor facilities
▪electric transmission, distribution and battery storage equipment
▪power generation plants, including renewable energy and natural gas-fired generation
▪marine and inland ethane and liquid fuels, LNG and LPG facilities, terminals and storage
▪nuclear power facilities and nuclear fuel and nuclear waste storage facilities (through SDG&E’s 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 for which our businesses could be liable; significant decreases in revenues and earnings; and/or other significant additional costs to us, including as a result of higher maintenance costs or restoration expenses, amounts to compensate third parties, and regulatory
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fines, penalties and disallowances. For our regulated utilities, these liabilities or increased costs may not be recoverable in rates. 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.
Moreover, weather-related incidents have become more prevalent, unpredictable and severe as a result of climate change or other factors, and we are currently in the midst of a severe global pandemic, any of which could have a greater impact on our businesses than is currently anticipated and, for our regulated utilities, rates may not be adequately or timely adjusted to reflect any such increased impact. Any such incident could have a material adverse effect on our 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 emissions; radioactive releases; explosions, spills or other significant damage to natural resources or property belonging to third parties; or personal injuries,
health impacts or fatalities, or could 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 in which the doctrine of inverse condemnation applies. We discuss how the application of this doctrine in California imposes strict liability on an electric 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 – Operational Risks.” 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.
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 risks and cyber risks that all large corporations face (e.g. malware, general cyber- or phishing-attacks by outsiders, malicious intent by insiders and inadvertent disclosure of sensitive information), we face evolving cybersecurity risks associated with protecting sensitive and confidential customer and employee information, smart grid infrastructure, and natural gas pipeline and storage infrastructure.
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, and our operations rely on complex, interconnected networks of generation, transmission, distribution, storage, control, and communication
technologies and systems. Existing business technologies and the deployment of new business technologies represent a large-scale opportunity for attacks on or other failures to protect our information systems and confidential information, as well as on the integrity of the energy grid and our natural gas infrastructure. In particular, various private and public entities have noted that cyber- and other attacks targeting utility systems and other energy infrastructures are increasing in sophistication, magnitude, and frequency. Additionally, the California Utilities are increasingly required to disclose large amounts of data (including customer energy usage and personal information regarding customers) to support changes to California’s electricity market related to grid modernization and customer choice, increasing the risks of inadvertent disclosure or other unauthorized access of sensitive information. Further, the virtualization of many business activities as a result
of the COVID-19 pandemic increases cyber risk, and there generally has been an associated increase in targeted cyber-attacks. Moreover, all of our businesses operating in California are subject to enhanced state privacy laws that have recently taken effect, which require companies that collect information on California residents to, among other things, make new disclosures to consumers about their data collection, use and sharing practices, allow consumers to opt out of certain data sharing with third parties and provide a new cause of action for breaches of certain highly sensitive categories of personal information resulting from a failure to reasonably secure them, and other states in which we do business could adopt similar laws in the future.
Addressing cyber risks is the subject of significant ongoing activities across Sempra Energy’s businesses, including investing in risk management and information security measures
for the protection of our systems and information. The cost and operational consequences of implementing, maintaining and enhancing system protection measures are significant, and they could materially increase to address increasingly intense, complex and sophisticated cyber risks. Despite our efforts, our businesses are not fully insulated from cyber-attacks or system disruptions. In addition, we often rely on third-party vendors to deploy new business
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technologies and maintain, modify and update our systems, including systems that manage sensitive information, and these third parties could fail to establish adequate risk management and information security measures with respect to these systems. Any 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, damage or improper disclosure of confidential customer or employee information or other sensitive data, could result in energy delivery service failures, financial and reputational loss, violations of privacy laws, fines or penalties, customer dissatisfaction and litigation, any of which could in turn have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects. Although Sempra Energy currently maintains cyber liability insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover any or even a substantial portion of the costs associated with the consequences of any compromise of our information systems or confidential information, and there is no guarantee that the insurance we currently maintain will continue to be available at rates
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 destruction of or disruption to our operating, financial and administrative systems that could materially adversely affect our business operations and the integrity of the power grid, our pipelines and distribution and storage infrastructure or one of our related facilities, 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.
Financial Risks
The substantial debt service obligations of Sempra Energy, SDG&E and SoCalGas could have a material adverse effect on our results of operations, cash flows, financial condition and/or prospects, and with respect to Sempra Energy, could require additional equity securities issuances.
The substantial debt service obligations of Sempra Energy, SDG&E and SoCalGas could have a material adverse effect on our results of operations, cash flows, financial condition and/or prospects by, among other things:
▪making it more difficult and costly for each of these companies to service, pay or refinance its debts as
they become due, particularly during adverse economic or industry conditions
▪limiting flexibility to pursue other strategic opportunities or react to changes in each of our businesses and the industry sectors in which they operate
▪requiring a substantial portion of available cash to be used for debt service payments, including interest and potential redemptions, thereby reducing the availability of cash to fund working capital, capital expenditures, development projects, acquisitions, dividend payments and other general corporate purposes
▪causing lenders to require additional materially adverse terms, conditions or covenants in the debt instruments for new debt, which might include restrictions on uses of proceeds or other assets or limitations
on the ability to incur additional debt, create liens, pay dividends, redeem or repurchase stock, make investments or receive distributions from subsidiaries or equity method investments
Sempra Energy is committed to maintaining or improving its current credit ratings. 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 or preferred stock. Additional equity issuances may dilute the voting rights and economic interests of existing holders of Sempra Energy’s common and preferred stock. There is no assurance that, should we elect to do so, we would be able to issue additional shares of Sempra Energy’s common or preferred stock with terms that we consider acceptable or at all or reduce the amount of our outstanding indebtedness 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.
The availability and cost of debt or equity financing could be adversely affected by conditions in the financial markets and economic conditions generally, as well as other factors, and any such negative effects could materially adversely affect us.
Our businesses are capital intensive and we rely on long-term debt to fund a significant portion of our capital expenditures and repay outstanding debt, and on short-term borrowings to fund a significant portion of day-to-day business operations. Sempra Energy may also seek to raise capital by issuing additional equity.
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Limitations
on the availability of credit, increases in interest rates or credit spreads or other negative effects on the terms of any debt or equity financing we may pursue could 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 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 capital for our businesses in addition to the terms of debt and equity financing, including, among others:
▪adverse
changes to economic and financial market conditions and laws and regulations in the jurisdictions in which we operate or do business
▪the overall health of the energy industry
▪volatility in natural gas or electricity prices
▪for Sempra Energy and SDG&E, risks related to California wildfires and any failure by the State of California to adequately address the financial and operational wildfire-related risks facing California electric IOUs
▪the deterioration of or uncertainty in the political or regulatory environment for local natural gas distribution companies operating in California
▪credit ratings
downgrades
We are subject to additional risks due to uncertainty relating to the calculation of LIBOR and its scheduled 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. The Financial Conduct Authority (FCA) in the United Kingdom, which regulates LIBOR, has emphasized the need for market participants to transition away from LIBOR. ICE Benchmark Administration, LIBOR’s administrator, with the support of the FCA, has indicated it will cease publication of certain key U.S. dollar LIBOR tenors in mid-2023 for existing loans. Additionally, the U.S. Federal Reserve has issued a statement advising banks to stop making new LIBOR-based issuances by the end of 2021. These could cause LIBOR
to perform differently than it has performed historically pending any discontinuance or modification and after any modification. The adoption of the Secured Overnight Financing Rate (SOFR), which has been identified as the replacement benchmark rate for LIBOR, may result in interest payments that are higher than expected or that do not otherwise correlate over time with the payments that would have been made on such indebtedness if the applicable LIBOR rate was available in its current form. Changes to or the discontinuance of LIBOR, any further uncertainty regarding the implementation of such changes or discontinuance, and uncertainties regarding the performance and characteristics of alternative benchmark rates, could have a material adverse effect on our existing and future variable rate indebtedness and/or borrowings, our existing and future interest rate hedges and the cost of doing business under our commercial agreements that incorporate LIBOR, and could require
us to seek to amend the terms of the relevant indebtedness or agreements, which may be on terms materially worse than existing terms. The occurrence of any of these risks could have a material adverse effect on our financial condition, cash flows and/or results of operations.
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 or other costs; the deterioration of, or uncertainty in, the political or regulatory environment for local natural gas distribution
companies operating in California; ability to generate cash flows; level of indebtedness; overall financial strength, including credit metrics; specific transactions or events, such as share repurchases; 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 can also have a material impact on the credit ratings of 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, some of
these ratings have experienced downgrades or have been moved to negative outlook in 2020 and there is no assurance that these credit ratings will not be further downgraded. In that regard, S&P has Sempra Energy, SDG&E and SoCalGas on negative outlook, and these negative outlooks could result in downgrades, or other negative credit
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rating actions could occur, at any time. We discuss these credit ratings further in “Part II – Item 7. MD&A – Capital Resources and Liquidity.”
For Sempra Energy, the Rating Agencies have noted that the following events, among other things, could lead to negative ratings actions:
▪Sempra Energy’s
failure to meet certain financial credit metrics
▪investing disproportionally in unregulated or uncontracted business and the impact on business mix and financial credit metrics over time
▪catastrophic wildfires caused by SDG&E, or catastrophic wildfires caused by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably earlier than expected
▪a ratings downgrade at SDG&E and/or SoCalGas
▪continuing to acquire shares under a share repurchase program
For SDG&E, the Rating Agencies have noted that the following events, among other things, could lead to negative ratings
actions:
▪SDG&E’s failure to meet certain financial credit metrics
▪the CPUC does not effectively implement the more supportive prudency standard for determining wildfire liability associated with the Wildfire Legislation
▪catastrophic wildfires caused by SDG&E, or catastrophic wildfires caused by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably earlier than expected
For SoCalGas, the Rating Agencies have noted that the following events, among other things, could lead to negative ratings actions:
▪SoCalGas’ failure to meet certain financial credit metrics
▪the
conclusion of the CPUC’s pending regulatory proceedings where key elements of SoCalGas’ credit profile are negatively impacted
▪deterioration of, or uncertainty in, the political or regulatory environment for local natural gas distribution companies operating in California
▪a ratings downgrade at Sempra Energy
A downgrade of Sempra Energy’s or either of the California Utilities’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, may materially and adversely affect the market prices of our 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 equity or debt securities and commercial paper and to raise other types of capital and/or complete additional financings, any of which could materially and adversely affect our ability to pay the principal of and interest on our debt securities and meet our other debt obligations and contractual commitments, and our cash flows, results of operations and/or financial condition.
We cannot and do not attempt to fully hedge our assets or contract positions against changes in commodity prices, and for those contract positions that are hedged, our hedging procedures may not mitigate our risk as 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, which 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 to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended or may not work as planned. In addition, daily value-at-risk and loss limits are primarily based on historic price movements. If prices significantly or persistently deviate
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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 and systems will prevent or mitigate losses that could materially adversely affect our results of operations, cash flows and/or financial condition.
Market performance or changes
in other assumptions could require significant unplanned contributions to 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 affected by other factors, including the assumed rate of return on plan assets, mortality tables, 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.
Legal and Regulatory Risks
Our businesses are subject to governmental regulations and tax and accounting requirements and may be materially adversely affected by these regulations or requirements or any changes to them.
The electric power and natural gas industries are subject to governmental regulations, and our businesses are also subject to complex accounting and tax requirements. The regulations and requirements that affect us may, from time to time, undergo significant changes on the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these regulations and requirements, including in the event of changes to these regulations and requirements or how they are implemented or interpreted, could materially and adversely affect how we conduct our
business and increase our operating costs. New tax legislation, regulations or interpretations in the U.S. and other countries in which we operate or do business could materially adversely affect our tax expense and/or tax balances, and changes in tax policies could materially adversely impact our businesses. Any failure to comply with these regulations and requirements could subject us to significant fines and penalties, including criminal penalties in some cases, and result in the temporary or permanent shutdown of certain facilities and operations. The occurrence of any of these risks could 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, cash flows, financial condition, results of operations and/or prospects.
Our businesses require numerous permits, licenses, franchises, and other approvals and agreements from various federal,
state, local and foreign governmental agencies, and the failure to obtain or maintain any of them could materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.
Our businesses and operations require numerous permits, licenses, rights-of-way, franchise agreements, certificates and other approvals and agreements from federal, state, local and foreign governmental agencies. These approvals may not be granted in a timely manner or at all or may be modified, rescinded or fail to be extended 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 are due to expire in December 2021 and June 2023, respectively, and SDG&E’s franchise agreement with the City of San Diego was scheduled to expire in January 2021. SDG&E
participated in the City’s competitive bid process for the franchises, which the City subsequently canceled. In December 2020, the City of San Diego and SDG&E agreed to extend the natural gas and electric franchises to June 1, 2021. The extension is intended to provide newly elected City officials time to seek public input and additional information. The City has announced its plan to start a new competitive bid process in the first quarter of 2021. Successfully obtaining, maintaining or renewing any or all of these approvals could result in higher costs or the imposition of conditions or restrictions on the manner in which we operate our businesses. Furthermore, our permits require compliance by us and may require compliance by our underlying customers. Failure by us or our customers to comply with permit, license, right-of-way or franchise requirements could result in these approvals and agreements being modified,
suspended
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or rescinded and could subject us to significant fines and penalties. If one or more of these approvals or agreements were to be suspended, rescinded or otherwise terminated, including due to expiration, or be modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise undesirable or impossible, we may be required to temporarily or permanently cease certain of our operations, sell the associated assets or remove them from service, construct new assets intended to bypass the impacted area, or any combination of the foregoing, in which case we may lose a significant portion of our rate base or other revenue generating assets, our prospects may be materially adversely affected and we may incur
significant impairment charges or other costs that may not be recoverable. The occurrence of any of these events could materially adversely affect our businesses financial condition, results of operations, cash flows and/or prospects.
We may invest significant amounts of money in major capital projects prior to receiving regulatory approval. If there is a delay in obtaining required regulatory approvals; if any regulatory approval is conditioned on major changes or other requirements that increase costs or impose restrictions on our existing or planned operations; if we fail to obtain or maintain required approvals or to comply with them or other applicable laws or regulations; if we are involved in litigation that adversely impacts any required approvals or rights to the applicable property; or if management decides not to proceed with a project, we may be unable to recover any or all amounts invested in that project. Any
such occurrence could cause our operations and prospects to materially decline and our costs to materially increase, result in material impairments, and otherwise materially adversely affect our businesses, financial condition, results of operations, cash flows 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,
among others. To comply with these legal requirements, we must spend significant amounts on environmental monitoring, pollution control equipment, mitigation costs and emissions fees, and these amounts could increase as a result of various factors that we may not control, including if these legal requirements change, permits are not issued, renewed or amended as anticipated, energy demands increase or our mix of energy supplies changes. Our regulated utilities may be materially adversely affected if these additional costs 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 off-site waste disposal sites that have been used in our operations. In
the case of our regulated utilities, some of these costs may not be recoverable in rates. Our facilities, including those of 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 and regulations may subject our businesses to substantial penalties and fines, including criminal penalties in some cases, 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 material negative effects on our operations, operating costs and the scope and economics of proposed expansions or other capital expenditures, which could have a material adverse effect on our results
of operations, cash flows and/or prospects. In particular, existing and potential state, national and international legislation and regulation relating to the control and reduction of GHG emissions may materially limit operations or otherwise materially adversely affect us. For example, SB 100 requires each California electric 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 of California’s retail electricity supply with a mix of RPS Program-eligible and zero-carbon resources by 2045. The law also includes stipulations that this policy not increase carbon emissions elsewhere in the western grid and not allow resource shuffling, and requires that the CPUC, CEC, CARB and other state agencies incorporate this policy into all relevant planning. In addition to signing SB 100 into law, the then-Governor of California also signed an executive
order establishing a new statewide goal to achieve carbon neutrality as soon as possible, and no later than 2045, and achieve and maintain net negative emissions thereafter. The executive order calls on CARB to address this goal in future scoping plans, which affect several major sectors of California’s economy, including transportation, agriculture, development, industrial and others. California recently issued new climate initiatives in line with this statewide goal, including two executive orders requiring sales of all passenger vehicles to be zero-emission by 2035. Our California Utilities and any of our other businesses impacted by similar future laws and regulations may be materially adversely affected if these additional costs are not recoverable in rates or, with respect to our non-regulated utility businesses, if such costs are not able to be passed through to customers. Even if such costs are recoverable, the effects of existing and proposed GHG emission reduction
standards may cause rates or other costs to customers to increase to levels that substantially reduce customer demand and growth, which may have a material adverse effect on the cash flows, performance, businesses and/or prospects of the
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California Utilities and any of our other affected businesses. SDG&E, as well as any of our other businesses affected by similar mandates in the future, 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, or interpretations or revisions to these laws, orders and regulations,
could result in requirements for additional monitoring, pollution monitoring and control equipment, safety practices, other operational changes to satisfy new mandates or emission fees, taxes or penalties, any of which could materially adversely affect our results of operations, financial condition 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 or other proceedings in which we are involved.
Sempra Energy and its subsidiaries are defendants in a number of lawsuits, binding arbitrations and regulatory proceedings, including in connection with the Aliso Canyon natural gas storage facility natural gas leak that we discuss in further detail below under “Risks Related to the California Utilities – Legal and Regulatory Risks.” We discuss material pending proceedings
in Note 16 of the Notes to Consolidated Financial Statements. We have spent, and continue to spend, substantial amounts of money, time and employee and management focus defending these lawsuits and proceedings and on related investigations and regulatory proceedings. The uncertainties inherent in lawsuits, arbitrations and other legal proceedings make it difficult to estimate with any degree of certainty the timing, 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. Any of the foregoing could cause significant reputational damage and materially adversely affect our businesses, results of operations, financial condition
and/or cash flows.
Risks Related to the California Utilities
Operational Risks
The California Utilities are subject to risks arising from the operation, maintenance and upgrade of their natural gas and electricity infrastructure and information technology systems, which, if they materialize, could materially and 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. Even though the California Utilities undertake substantial capital investment projects to construct, replace, maintain, improve and upgrade these facilities
and systems, 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, and these risks could be amplified while capital investment projects are in process. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could also be adversely affected by events occurring on the systems of such third parties, some of which may be unanticipated or uncontrollable by us.
Additional risks associated with the ability of 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, among others:
▪failure to meet customer demand for natural gas and/or electricity, curtailments, controlled or uncontrolled gas outages, or gas surges back into homes that could cause serious personal injury or loss of life
▪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
▪the release of hazardous or toxic substances into the air, water or soil, including gas leaks
▪severe weather events or natural disasters, pandemics, or attacks by third parties such as cyber-attacks, acts of terrorism,
vandalism or war, the effects of which we discuss above under “Risks Related to All Sempra Energy Businesses – Operational Risks”
▪inadequate emergency preparedness plans and the failure to respond effectively to catastrophic events that could lead to public or employee harm or extended outages
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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. Any such events could materially adversely
affect Sempra Energy’s and one or both of the California Utilities’ financial condition, cash flows and/or results of operations.
Wildfires in California pose a significant risk to the California Utilities’ (particularly SDG&E’s) and Sempra Energy’s business, financial condition, results of operations and/or cash flows.
Potential for Increased and More Severe Wildfires
In 2020, California experienced some of the largest wildfires (measured by acres burned) in its history. Frequent and more severe drought conditions, inconsistent and extreme swings in precipitation, changes in vegetation caused by these precipitation swings or other factors, unseasonably warm temperatures, very low humidity and stronger winds have increased the duration of the wildfire season and the intensity and prevalence of wildfires in California, including in
SDG&E’s and SoCalGas’ service territories, and have made these wildfires increasingly difficult to predict and contain. Changing weather patterns, including as a result of climate change, could cause these conditions to become even more extreme and unpredictable. These wildfires could place third-party property and the California Utilities’ electric and natural gas infrastructure in jeopardy and reduce the availability of hydroelectric generators, and these wildfires and the associated weather conditions could result in temporary power shortages in SDG&E’s and SoCalGas’ service territories. In addition, certain of California’s local land use policies and forestry management practices have been relaxed to allow for the construction and development of residential and commercial projects in high-risk fire areas that may not have the infrastructure or contingency plans necessary to address wildfire risks, which could lead to increased third-party claims and greater
losses for which SDG&E or SoCalGas may be liable. We discuss the effects wildfires or other natural disasters could have on our businesses, including the ways in which they could materially adversely affect the California Utilities’ and Sempra Energy’s business, financial condition, results of operations and/or cash flows, in this risk factor below and above under “Risks Related to All Sempra Energy Businesses – Operational Risks.”
The Wildfire Legislation
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, safety certifications, and the establishment of a wildfire safety board. The Wildfire Legislation did not change the doctrine of inverse condemnation, which imposes strict liability (meaning that liability is imposed regardless of fault) on a utility whose equipment, such as its electric distribution and transmission lines, is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including potential business interruption losses, as well as interest and attorneys’ fees, even if the utility has not been found negligent. The doctrine of inverse condemnation also is not exclusive of other theories of liability, including if the utility were found negligent, in which case additional liabilities, such as fire suppression, clean-up and evacuation costs, medical expenses, and personal injury, punitive and other damages, could be imposed. 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 wildfire-related claims against a participating IOU in the event that the governmental agency responsible for determining causation determines such IOU’s equipment caused the ignition of a wildfire, primary insurance coverage is exceeded and certain other conditions are satisfied. However, the standards prescribed by the Wildfire Legislation may not be effectively implemented or applied consistently by the State of California 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. Although SDG&E is not aware of any claims
made against the Wildfire Fund by any participating IOU, there is no assurance that one or more participating IOUs will not submit claims against the Wildfire Fund in connection with any past or future wildfires. As a result, we are unable to predict whether the Wildfire Legislation will be effectively implemented or consistently applied or its impact on SDG&E’s ability to recover certain costs and expenses in the event that SDG&E’s equipment is determined to be a cause of a fire, and specifically in the context of the application of inverse condemnation. If a major fire is determined to be caused by SDG&E’s equipment, or if a major fire is determined to be caused by another California electric IOU and the Wildfire Fund is depleted as a result, Sempra Energy’s and SDG&E’s business, financial condition, results of operations and/or cash flows could be materially adversely affected.
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Cost
Recovery Through Insurance or Rates
We have experienced increased costs and difficulties in obtaining insurance coverage for wildfires that could be caused by the California Utilities’ operations, particularly SDG&E’s operations, and these conditions could continue or worsen. As a result of the strict liability standard applied to electric IOU-caused wildfires in California, substantial recent losses recorded by insurance companies, and the risk of an increase in the number and size of wildfires, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, the insurance that has been obtained for wildfire liabilities and the insurance for these liabilities that may be available in the future, if any, may not be sufficient to cover all losses that we may incur, or it may not be available in sufficient amounts to meet the $1 billion of primary insurance
required by the Wildfire Legislation. Uninsured losses may not be recoverable in customer rates and increases in the cost of insurance may be challenged when we seek cost recovery through the regulatory process. 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. A loss which is not fully insured, sufficiently covered by the Wildfire Fund and/or cannot be recovered in customer rates, such as the CPUC decision denying SDG&E’s recovery of costs related to wildfires in its service territory in 2007, could materially adversely affect Sempra Energy’s and one or both of the California Utilities’ financial condition, cash flows and/or results of operations.
Wildfire Mitigation Efforts
Although we spend significant resources on measures designed to mitigate wildfire risks, there is no assurance that these
measures will be successful or effective in reducing our wildfire-related losses or that their costs will be fully recoverable in rates. The California Utilities are required by applicable California law to submit annual wildfire mitigation plans for approval by the Wildfire Safety Division of the CPUC and could be subject to increased risks if these plans are not approved in a timely manner and fines or penalties for any failure to comply with the approved plans. One of our wildfire mitigation tools is to de-energize certain of our facilities when weather conditions become extreme and there is elevated wildfire ignition risk, in an effort to help mitigate this safety risk to the public. Such “public safety power shutoffs” have been subject to significant scrutiny by various stakeholders, including customers, regulators and law makers, that could lead to legislation or rulemaking that increases the risk of penalties and liability for damages associated with these
events. Such costs may not be recoverable in rates. Unrecoverable costs, adverse legislation or rulemaking, scrutiny by key stakeholders or other negative effects associated with wildfire mitigation efforts could materially adversely affect Sempra Energy’s and SDG&E’s financial condition, cash flows and/or results of operations.
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 generation, energy storage, energy efficiency and demand response technologies, and California’s environmental policy objectives are accelerating the pace and scope of these industry changes. This growth of distributed energy resources will require
modernization of the electric distribution grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect distributed energy resources. Moreover, enabling California’s clean energy goals will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options and electric vehicle infrastructure. The CPUC is conducting proceedings to: evaluate various 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; determine what, if any, compensation would be feasible and appropriate; and clarify the role of the electric distribution grid operator. These proceedings
and the broader changes in California’s electricity industry could result in new regulations, policies and/or operational changes that could materially adversely affect SDG&E’s and Sempra 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 and CCA is only available if a customer’s local jurisdiction (city) offers such a program. Several local jurisdictions, including the City and County of San Diego and other municipalities, have implemented, are implementing
or are considering implementing CCA, which could result in SDG&E providing procurement service for less than half of its current customer load as early as December 31, 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. Existing state law requires that customers opting to have CCA procure their electricity must absorb the cost of above-market electricity procurement commitments already made by SDG&E on their behalf, which requirements are designed to equitably share costs among customers served by SDG&E and
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customers
served by DA and CCA. If adequate mechanisms are not implemented to help ensure compliance with state law or if state law changes, 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 or, if all such costs are not recoverable in rates, SDG&E could experience material increases in its unrecoverable commodity costs. If legislative, regulatory or legal action is taken that has the effect of preventing or delaying recovery of these procurement costs or if mechanisms are not in place to help 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/or results of operations.
Natural gas and natural gas storage have increasingly been the subject of political and public scrutiny, including
a desire by some to substantially reduce or eliminate reliance on natural gas as an energy source.
Certain California legislators and stakeholder, advocacy and activist groups have expressed a desire to further limit or eliminate reliance on natural gas as an energy source by advocating increased use of renewable electricity and electrification in lieu of the use of natural gas. Certain California state agencies have recently proposed public policies that would prohibit or restrict the use and consumption of natural gas, for example in new buildings and appliances, and certain local city governments have passed ordinances restricting use of natural gas connections in newly constructed buildings. These proposals and ordinances and any other similar regulatory action could have the effect of reducing natural gas use over time. In addition, CARB, California’s primary regulator for GHG emission reduction programs, has published
plans for reducing GHG emissions in line with California’s climate goals that include proposals to reduce natural gas demand, including more aggressive energy efficiency programs to reduce natural gas end use, increased renewable generation in the electric sector reducing noncore gas load, and replacement of natural gas appliances with electric appliances. CARB’s plans also propose that some conventional natural gas be displaced with above-market renewable natural gas, which could result in increased costs that may not be fully recoverable in rates, and CARB is currently considering updates to its GHG reduction plans, which are due to be finalized in 2022, that could further reduce natural gas demand. The CPUC has 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 two phases, the first of which is addressing reliability standards and coordination between natural gas utilities and natural gas-fired electric generators, and the second of which will implement a long-term planning strategy. A substantial reduction or the elimination of natural gas as an energy source in California could lead to certain of SoCalGas’ and SDG&E’s gas assets no longer meeting CPUC standards to recover costs and earn an associated rate of return, thus potentially causing our substantial investment in the value of these gas assets to be depreciated on an accelerated basis or become stranded, and could otherwise have a material adverse effect on SoCalGas’, SDG&E’s and Sempra Energy’s cash flows, financial condition and/or 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, among other things:
▪the potential release of a radioactive material, including from a natural disaster, that could cause catastrophic harm to human health and the environment
▪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
▪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
▪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, an adverse change in the law regarding funding requirements for decommissioning
trusts, or changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment could increase the funding requirements for these trusts, which costs 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 altogether if the CPUC determines that the expenditures are unreasonable. In addition, decommissioning may be materially more expensive than
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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.
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.
We discuss SONGS further in Note 15 of the Notes to Consolidated Financial Statements.
Legal and Regulatory Risks
The California Utilities are subject to extensive regulation by state, federal and local legislative and regulatory authorities, which may materially adversely affect us.
Rates and Other Capital-Related Matters
The CPUC regulates the California Utilities’ customer rates, except for SDG&E’s electric transmission rates which are regulated by the FERC. The CPUC also regulates, among other
matters, the California Utilities’:
▪conditions of service
▪sales of securities
▪rates of return
▪capital structure
▪rates of depreciation
▪long-term resource procurement
The CPUC periodically approves the California Utilities’ customer rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments, as well as settlements with third parties, while incorporating a risk-based decision-making framework. The outcome
of ratemaking proceedings can be affected by various factors, many of which are not in our control, including, among others, the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of applicable regulators, consumer and other stakeholder organizations and customers about the California Utilities’ ability to provide safe, reliable, and affordable electric and gas services. These ratemaking proceedings include decisions about major programs in which SoCalGas and SDG&E make significant investments under an approved CPUC framework, but which investments may remain subject to a CPUC reasonableness review or filing that could result in the disallowance of a portion of the incurred costs. The California Utilities also may be required to incur costs and make investments to comply with legislative and regulatory requirements and initiatives,
such as those relating to the development of a state-wide electric vehicle charging infrastructure, the deployment of distributed energy resources, implementation of demand response and customer energy efficiency programs, energy storage and renewable energy targets, gas distribution and transmission safety and integrity, and underground gas storage, among others. The California Utilities’ ability to recover these costs and investments depends in part on the final form of the legislative or regulatory requirements and the ratemaking mechanisms associated with them, and could also be impacted by the timing and process of the ratemaking mechanism, in which there is a potentially significant time lag between when costs are incurred and when those costs are recovered in customers’ rates and there could be potentially material differences between the forecasted or authorized costs embedded in rates (which are set on a prospective basis) and the amount of actual costs incurred.
The cash flows, results of operations, financial condition and/or prospects of Sempra Energy and each of the California Utilities may be materially adversely affected by their rates, which can be impacted by, among other things:
▪delays by the CPUC on decisions regarding recovery
▪the results of after-the-fact reasonableness reviews with unclear standards
▪finalization of legislative and regulatory requirements and initiatives in an unexpected manner
▪rejection of settlements with third parties
▪decisions denying recovery or authorizing less than full recovery on the basis that costs were not reasonably
or prudently incurred or for other reasons
▪actual capital expenditures or operating costs exceeding the amounts approved by the CPUC
In addition, changes in key benchmark interest rates may trigger automatic adjustment mechanisms that determine the California Utilities’ authorized rates of return. Specifically, the CCM considers changes in interest rates based on the applicable 12-month average Moody’s utility bond index. If triggered, the CCM would automatically update the California Utilities’ authorized cost of debt based on actual costs and authorized ROE upward or downward by one-half of the difference between the CCM benchmark
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and the
applicable 12-month average Moody’s utility bond index. For the 12-months ended September 30, 2020, SDG&E and SoCalGas were close to their respective benchmark rates but did not trigger the CCM. Interest rates referenced in the applicable Moody’s utility bond indices have been more than 100 bps below the benchmark since the beginning of the current measurement period. If these interest rates remain at current levels through the remainder of the current measurement period, a triggering event for SDG&E and SoCalGas could occur. A trigger of the CCM in 2021 that requires a downward adjustment could materially adversely affect the results of operations and cash flows of Sempra Energy and, depending on the CCM that is triggered, SDG&E and SoCalGas, beginning January 1, 2022. We discuss the CCM further in “Part I – Item 1. Business – Ratemaking Mechanisms – California
Utilities – Cost of Capital Proceedings” and in Note 4 of the Notes to Consolidated Financial Statements.
The FERC regulates electric transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the rates of return on investments in electric transmission assets, and other similar matters involving SDG&E. These ratemaking mechanisms are subject to many risks similar to those described above regarding the CPUC.
CPUC Authority Over Operational Matters
The CPUC has regulatory authority related to utility operations, safety standards and practices, competitive conditions, reliability and planning, affiliate relationships and a wide range of other matters, including citation programs concerning matters such as safety activity, disconnection
and billing practices, resource adequacy and environmental compliance. Many of these standards and programs are becoming more stringent and could impose severe penalties. For example, SDG&E and SoCalGas are subject to a safety enforcement program developed by the CPUC pursuant to SB 291 that includes procedures for monitoring, data tracking and analysis, and investigations, and delegates citation authority to CPUC staff under the direction of the CPUC Executive Director. The CPUC staff has authority to issue citations up to an administrative limit of $8 million per citation under this program, and penalties issued by the CPUC under the program can exceed this administrative limit, having exceeded $1.5 billion in one instance for an unrelated third party. The CPUC conducts various reviews and audits of the matters under its authority, including compliance with CPUC regulations, and could launch investigations or open proceedings at any time on any issue it deems appropriate,
the results of which could lead to citations, disallowances, fines and penalties. Any such citations, disallowances, fines or penalties for noncompliance with any CPUC regulations, programs or standards, as well as any corrective or mitigation actions required to become in compliance if not sufficiently funded in customer rates, could have a material adverse effect on Sempra Energy’s and the California Utilities’ results of operations, financial condition, cash flows and/or prospects. 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.
Influence of Other Organizations and Potential Regulatory Changes
The California Utilities and Sempra Energy may be materially adversely affected by revisions or reinterpretations of existing
or new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies, any of which could change how the California Utilities operate, affect their ability to recover various costs through rates or adjustment mechanisms, or require them to incur substantial additional expenses.
The California Utilities are also affected by the activities of organizations such as Cal PA, TURN, Utility Consumers’ Action Network, Sierra Club and other stakeholder, advocacy and activist groups. To the extent that any of these groups are successful in directly or indirectly influencing the California Utilities’ operations, this could have a material adverse effect on the California Utilities’ and Sempra Energy’s businesses, cash flows, results of operations, financial condition and/or prospects.
SoCalGas has incurred and may continue to incur significant
costs, expenses and other liabilities related to the Leak, a substantial portion of which may not be recoverable through insurance.
From October 23, 2015 through February 11, 2016, SoCalGas experienced a natural gas leak from one of the injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility in Los Angeles County. As described in Note 16 of the Notes to Consolidated Financial Statements, numerous lawsuits, investigations and regulatory proceedings have been initiated in response to the Leak, resulting in significant costs.
Civil and Criminal Litigation
As of February 22, 2021, 395 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. The initial trial previously scheduled for June 2020 for a small number of randomly selected individual plaintiffs was postponed, with a new trial date yet to be determined by the court.
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Four shareholder derivative actions were filed alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas. Three of the actions were joined in an Amended Consolidated Shareholder Derivative Complaint, which was dismissed with
prejudice in January 2021. The remaining action was also dismissed but plaintiffs were given leave to amend their complaint.
A misdemeanor criminal complaint was filed by the Los Angeles County District Attorney’s office, as to which SoCalGas entered a settlement that was approved by the LA Superior Court; challenges by certain residents have been rejected by the California Supreme Court.
Additional litigation, including by public entities, and criminal complaints may be filed against us related to the Leak or our responses thereto.
The costs of defending against or settling or otherwise 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. We discuss these risks further above under “Risks Related to All Sempra Energy Businesses – Legal and Regulatory Risks” and in this risk factor below under “Insurance and Estimated Costs.”
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 did not identify any instances of non-compliance by SoCalGas and concluded that SoCalGas’ compliance activities conducted prior to the Leak did not find indications of a casing integrity issue, but also opined that there were measures, though not 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.
In June 2019, the CPUC opened an OII to consider penalties against SoCalGas for the Leak. The first phase will consider whether SoCalGas violated applicable laws, CPUC orders or decisions, rules or requirements, whether SoCalGas engaged in unreasonable and/or imprudent practices with respect to its operation and maintenance of the Aliso Canyon natural gas storage facility or its related record-keeping practices, whether SoCalGas cooperated sufficiently with the SED 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, the 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 on a subset of issues are scheduled to begin in March 2021. The second phase will consider whether SoCalGas should be sanctioned for the Leak and what damages, fines or other penalties or sanctions, if any, should be imposed for any violations unreasonable or imprudent practices, or failure to sufficiently cooperate with the SED as determined by the CPUC in the first phase. In addition, the second phase will determine the amounts of various costs incurred by SoCalGas and other parties in connection with the Leak and the ratemaking treatment or other disposition of such costs, which could result in little or no recovery of such costs by SoCalGas. SoCalGas has engaged in settlement discussions with the SED in connection with this proceeding.
Higher operating costs and additional capital expenditures incurred by SoCalGas as a result of these investigations or 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 and penalties, any of which could cause significant reputational damage. The occurrence of any of these risks could materially adversely affect SoCalGas’ and Sempra Energy’s cash flows, financial condition and/or results of operations.
Natural Gas Storage Operations and Reliability
Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and consumer heating needs in the winter. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important 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 injection operations in July 2017 based on limited operating ranges for the field. In February 2017, the CPUC opened a proceeding pursuant to SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including considering alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated.
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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, 2020, the Aliso Canyon natural gas storage facility had a net book value of $821 million. Any significant impairment of this asset, or higher operating costs and additional capital expenditures incurred by SoCalGas that 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/or cash flows.
Insurance and Estimated Costs
At December
31, 2020, SoCalGas estimates certain costs related to the Leak are $1,627 million (the cost estimate), which includes the $1,279 million of costs recovered or probable of recovery from insurance. This cost estimate may increase significantly as more information becomes available. A substantial portion of the cost estimate has been paid, and $451 million is accrued as Reserve for Aliso Canyon Costs as of December 31, 2020 on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets.
The actions against us related to the Leak as described in this risk factor above under “Civil and Criminal Litigation” seek compensatory, statutory and punitive damages, restitution, and civil, administrative and criminal fines, penalties and other costs. In addition, we could be subject to damages, fines, or other penalties or sanctions as a result of the investigations and other matters
described in this risk factor above under “Governmental Investigations, Orders and Additional Regulation.” Except for the amounts paid or estimated to settle certain actions, as described in this risk factor above under “Civil and Criminal Litigation,” the cost estimate does not include litigation, regulatory proceedings or regulatory costs to the extent it is not possible to predict at this time 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. 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. These costs not included in the cost estimate
could be significant and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
We have received insurance payments for many of the costs included in the cost estimate, and we intend to pursue the full extent of our insurance coverage for all other costs we have incurred. Other than insurance for certain future defense costs we may incur as well as directors’ and officers’ liability, we have exhausted all of our insurance in this matter. We continue to pursue other sources of insurance coverage for costs related to this matter, but we may not be successful in obtaining additional insurance recovery for any of these costs. If we are not able to secure additional insurance recovery, if any costs we have recorded as an insurance receivable are not collected, if there are delays in receiving insurance recoveries, or if the insurance recoveries are subject
to income taxes while the associated costs are not tax deductible, such amounts, which could be significant, could have a material adverse effect on SoCalGas’ and Sempra 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.
The failure by the CPUC to adequately reform SDG&E’s rate structure, including the implementation of charges independent of consumption volume and measures to reduce NEM rate subsidies, 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 NEM program is an electric billing tariff mechanism designed to
promote the installation of on-site renewable generation (primarily solar installations) for residential and business customers. Under 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. 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 exceptions, 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 more electric-use customers and 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 non-NEM customers.
The current electric residential rate structure in California is primarily based on consumption volume, which places a higher rate burden on customers with higher electric use while subsidizing lower use customers. In July 2015, the CPUC adopted a decision that provided a framework for rates that could be more transparent, fair and sustainable. The framework provides for a minimum
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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. Most elements of the framework were implemented in 2020 and should result in some relief for higher-use customers and a
rate structure that better aligns rates with actual costs to serve customers. The decision also established a process for electric utilities to seek implementation of a fixed charge for residential customers, subject to certain conditions; however, in March 2020, the CPUC adopted a decision rejecting electric utilities’ requests to establish a fixed residential charge. The decision allows the utilities to renew their requests for a fixed charge at a later date if such proposals include an adequate customer outreach and communications plan. In August 2020, the CPUC initiated a rulemaking to further develop a successor to the existing NEM tariff. We expect a decision establishing a successor tariff to be issued in the fourth quarter of 2021, with implementation of the successor tariff by January 2022. Depending on the structure and functionality of such a successor tariff, which is uncertain, the current risks associated with the existing NEM tariff could continue or increase.
SDG&E
believes the establishment of a charge independent of consumption volume for residential customers is critical to help ensure rates are distributed among all customers that rely on the electric transmission and distribution system, including those participating in the NEM program. In addition, distributed energy resources and energy efficiency initiatives could generally reduce delivered volumes, increasing the importance of a fixed charge. The absence of a charge independent of consumption volume coupled with the continuing increase of solar installation and other forms of self-generation could adversely impact electricity rates and the reliability of the electric transmission and distribution system, which could subject SDG&E to higher levels of customer dissatisfaction, increased likelihood of noncompliance with CPUC or other safety or operational standards, and increased risks attendant to any such noncompliance as we discuss above under “Risks Related to
the California Utilities – Legal and Regulatory Risks,” and also could increase SDG&E’s costs, including power procurement, operating or capital costs, and increase the likelihood of disallowance of recovery for these costs.
If the CPUC fails to adequately reform SDG&E’s rate structure to better achieve reasonable, cost-based electric rates that are competitive with alternative sources of power and adequate to maintain the reliability of the electric transmission and distribution system, such failure could have a material adverse effect on SDG&E’s and Sempra Energy’s business, 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 established in connection with our acquisition of an 80.25% indirect interest in Oncor in March 2018, we and Oncor are subject to various restrictions, including, among others:
▪seven members of Oncor’s 13-person board of directors will be independent directors in all material respects under the rules of the NYSE in relation
to Sempra Energy and its subsidiaries and affiliated entities and any other direct or indirect owners of Oncor, and also will have no material relationship with Sempra Energy and its subsidiaries and affiliated entities or any other direct or indirect owners of Oncor currently or within the previous 10 years. With respect to the six remaining directors, two will be designated by Sempra Energy, two will be designated by Oncor’s minority owner, TTI, and two will be current or former Oncor officers
▪Oncor will not pay any dividends or other distributions (except for contractual tax payments) if a majority of its independent directors or any of the directors appointed by TTI determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements
▪Oncor will not pay dividends or other
distributions (except for contractual tax payments) if that payment would cause its debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT
▪if Oncor’s senior secured debt credit rating by any of the 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
▪there must be maintained certain “separateness measures” that reinforce the legal and financial separation of Oncor from Sempra Energy, including a requirement that dealings between Oncor and Sempra Energy or Sempra Energy’s affiliates (other than Oncor Holdings and its subsidiaries) must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or stock
for any entity other than Oncor
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▪a majority of Oncor’s independent directors and the directors designated by TTI that are present and voting (of which at least one must be present and voting) must approve any annual or multi-year budget if the aggregate amount of capital expenditures or O&M in such budget is more than a 10% increase or decrease from the corresponding amounts of such expenditures in the budget for the preceding fiscal year or multi-year period, as applicable
▪Sempra Energy will continue to hold indirectly at least 51% of the ownership interests in Oncor Holdings and Oncor until at least March
9, 2023, 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 boards of directors, which are each controlled by independent directors. Moreover, all directors of Oncor, including those directors we have appointed, 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 in certain cases be contrary to our best interests or be in opposition to our preferred strategic direction for Oncor. To the extent that the directors approve
or Oncor otherwise pursues actions that are not in our interests, the financial condition, results of operations, cash flows and/or prospects of Sempra Energy may be materially adversely affected.
Changes in the electric utility industry, including changes in regulation of ERCOT, could materially adversely affect Oncor’s results of operations, cash flows, financial condition and/or prospects, which could materially adversely affect us.
Oncor operates in the electric utility sector and is subject to various legislative requirements and regulations by U.S., Texas and regional and local authorities. As a result, it is subject to many of the same or similar risks as our California Utilities as we describe above under “Risks Related to the California Utilities.” The costs and burdens associated with complying with these requirements and adjusting Oncor’s business and operations
in response to legislative and regulatory developments, including changes in ERCOT, and any fines or penalties that could result from any noncompliance, may have a material adverse effect on Oncor. Moreover, potential legislative, regulatory or market or industry changes may jeopardize the predictability of utility earnings generally. In February 2021, following extreme winter weather, the PUCT issued a moratorium on customer disconnections due to nonpayment and could take other similar measures to address financial challenges experienced by other ERCOT market participants, which could adversely impact Oncor’s collections and cash flows and, in turn, could adversely impact us. Also in February 2021, ERCOT required transmission companies, including Oncor, to significantly reduce demand on the grid due to insufficient electricity generation caused by extreme winter weather, resulting in power outages throughout ERCOT. The Governor of Texas has declared reform of ERCOT
as an emergency item for the current Texas Legislative session. Various regulatory and governmental entities have indicated an intent to investigate the operation of the ERCOT grid during this extreme winter weather event and additional inquiries could also arise. Any significant changes relating to the ERCOT market that impact transmission and distribution utilities as a result of such proceedings or otherwise could materially adversely impact Oncor. If Oncor does not successfully respond to these changes and any other legislative, regulatory, or market or industry changes applicable to it, Oncor could suffer a deterioration in its results of operations, financial condition, cash flows and/or prospects, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Oncor’s operations are capital intensive and it could have liquidity needs that necessitate 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 from operations and with proceeds from indebtedness, but these sources of capital may not be adequate in the future. Our commitments to the PUCT prohibit us from making loans to Oncor. As a result, if Oncor fails to meet its capital requirements or if Oncor is unable to access sufficient capital to finance its ongoing needs, we may elect to make additional capital contributions to Oncor. Any such investments could be substantial and would reduce the cash available to us for other purposes, could increase our indebtedness and could ultimately materially adversely affect our results of operations, cash flows, financial condition and/or prospects.
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 spin-off), and Vistra became an independent, publicly traded company. Vistra’s spin-off from EFH was intended to qualify for partially tax-free treatment to EFH and its shareholders under Sections 368(a)(1)(G), 355 and 356 of the IRC (collectively referred to as the Intended Tax Treatment). In connection with and as a condition to the spin-off, EFH received a private letter ruling from
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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 of EFH with an indirect subsidiary of Sempra Energy, with EFH continuing as the surviving company and as an indirect, wholly owned subsidiary of Sempra Energy (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 counsels that generally provide that the Merger will not affect the conclusions reached in, respectively, the IRS private letter ruling and tax opinions issued with respect to the spin-off described above. Similar to the IRS private letter ruling and opinions issued with respect to the spin-off, the supplemental private letter ruling is
generally binding on the IRS and any opinions issued with respect to the Merger are based on factual representations and assumptions, as well as certain undertakings, made by Sempra 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 challenged by the IRS. Even though Sempra Texas Holdings Corp. would have administrative appeal rights if the IRS were to invalidate its private letter ruling and/or supplemental private letter ruling, including the right to challenge any adverse IRS position in court, any such appeal would
be subject to significant uncertainties and could fail. If it is ultimately determined that the Merger caused the spin-off not to qualify for the Intended Tax Treatment, Sempra 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.
Risks Related to Our Businesses Other Than the California Utilities and Our Interest in Oncor
Operational Risks
Project 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.
All Energy Infrastructure Projects
We are involved in a number of energy infrastructure projects, including natural gas liquefaction facilities; 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 projects. The acquisition, development, construction and expansion of these projects involve numerous risks.
We may be required to spend significant sums for preliminary engineering, permitting, fuel supply, infrastructure development, legal and other expenses before
we can determine whether a project is feasible, economically attractive, or capable of being built. If the project is not completed, we may have to impair or write off amounts that we have invested in project development and never receive any return on these preliminary investments.
Success in developing a project is contingent upon, among other things:
▪our ability to reach a final investment decision or otherwise make progress with respect to any project, which may be dependent on our financial condition and cash flows and may be influenced by a number of external factors outside our control, including the global economy and global energy and financial markets
▪negotiation of satisfactory EPC agreements, including any renegotiation of total contract price and other terms that
may be required in the event of delays in final investment decisions or other failures to meet specified deadlines with respect to a project
▪if we intend to have equity partners in the project, identification of suitable partners and negotiation of satisfactory equity agreements
▪identification of suitable customers and negotiation of satisfactory LNG offtake or other customer agreements
▪negotiation of satisfactory supply, natural gas and LNG sales agreements or firm capacity service agreements and PPAs
▪timely receipt of required governmental permits, licenses and other authorizations that do not impose material conditions and are otherwise granted under terms we find reasonable,
as well as maintenance of these authorizations
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▪our project partners’ willingness and financial or other ability to make their required investments on a timely basis
▪our contractors and other counterparties’ willingness and financial or other ability to fulfill their contractual commitments
▪timely, satisfactory and on-budget completion of construction, which could be negatively affected by engineering problems, adverse weather conditions or other natural disasters, pandemics, cyber- or other attacks by third parties, work stoppages, equipment unavailability, contractor performance
shortfalls and a variety of other factors, many of which we discuss above under “Risks Related to All Sempra Energy Businesses – Operational Risks” and in this risk factor below
▪obtaining adequate and reasonably priced financing for the project
▪the absence of hidden defects or inherited environmental liabilities for any brownfield project construction
▪fast and cost-effective resolution of any litigation or unsettled property rights affecting a project
Any failures with respect to the above factors or other factors material to any particular project could involve significant additional costs to us and otherwise materially adversely affect the successful completion of a project. If we are unable
to complete a development project, if we experience substantial delays, or if construction, financing or other project costs exceed our estimated budgets and we are required to make additional capital contributions, our businesses, financial condition, cash flows, results of operations and/or prospects could be materially adversely affected.
The operation of existing facilities, such as Cameron LNG JV’s Phase 1 facility, and any future projects we are able to complete involves many risks, including, among others, the potential for unforeseen design flaws, engineering challenges, equipment failures or the breakdown for other reasons 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, pandemics, cyber- or other attacks by third parties and other similar events can disrupt liquefaction, generation, regasification, storage, transmission and distribution systems and have other impacts that we discuss above under “Risks Related to All Sempra Energy Businesses – Operational Risks.” The occurrence of any of these events could lead to our facilities being idle for an extended period of time or our facilities operating below expected capacity levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Any such occurrence could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.
LNG Export Projects
In addition to the risks described above that are applicable to all our energy infrastructure projects, we are
exposed to additional risks in connection with our LNG export projects, including Cameron LNG JV’s Phase 1 project and our potential development of additional LNG export facilities. Sempra LNG is in discussions with the co-owners of Cameron LNG JV regarding the potential expansion of the facility in Phase 2 to include up to two additional liquefaction trains, is developing a proposed natural gas liquefaction export project near Port Arthur, Texas, and, through a JV agreement with IEnova, is developing a proposed natural gas liquefaction export project at IEnova’s existing ECA Regas Facility in Baja California, Mexico to be developed in two phases (a mid-scale project referred to as ECA LNG Phase 1 and a large-scale project referred to as ECA LNG Phase 2). These projects are at various stages of development, and we have only reached a final investment decision with respect to ECA LNG Phase 1, which occurred in the fourth quarter of 2020. We discuss each of our LNG export
projects further in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra LNG.”
Each of these projects faces numerous risks and must overcome significant hurdles. Our ability to reach a final investment decision for each project and, if such a decision is reached and a project is completed, the overall success of such project are dependent on global energy markets, including natural gas and oil supply, demand and pricing. In general, 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. Such a reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, or as a result of calls
by some to limit or eliminate reliance on natural gas as an energy source globally. Any of these developments could result in increased or decreased competition and impact prospects for developing projects in an environment of declining LNG demand, and could negatively affect the performance and prospects of any of our projects that are or become operational. Moreover, if and as our development projects become operational, such projects could become competitive against each other, which would harm the overall success of our LNG export strategy. At certain moderate levels, oil prices could also make LNG projects in other parts of the world more feasible and competitive with LNG projects in North America, thus increasing supply and competition for 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 (based on Henry Hub pricing), which could further decrease demand for domestic LNG and increase competition among LNG project developers.
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There are a number of potential new LNG projects in addition to ours that are under construction or in the process of development by various project developers in North America, and given the projected global demand for LNG and the inherent risks of these projects, the vast majority of these projects likely will not be completed. Our proposed projects may face distinct disadvantages relative to some of the other projects under construction or in development. For example:
▪Our Port Arthur, Texas project
is a greenfield site, and therefore it does not have some of the advantages often associated with brownfield sites. Some of these disadvantages include increased costs and time to construct, which could materially adversely affect the development of this project.
▪The proposed expansion of the Cameron LNG JV facility (Phase 2) is subject to certain restrictions and conditions under the project financing agreements for Phase 1 of the project, including, among others, timing restrictions unless appropriate prior consent is obtained from the project lenders, and requires unanimous consent of all JV partners, including with respect to the equity investment obligations of each partner. There is no assurance that these conditions and requirements can be satisfied, in which case our ability to develop the Phase 2 project would be jeopardized.
▪The
ECA Regas Facility, the ECA LNG Phase 1 liquefaction export project under construction and the potential ECA LNG Phase 2 liquefaction export project in Mexico are subject to ongoing land and permit disputes that could make finding or maintaining suitable partners and customers, difficult, and could also hinder or halt construction and, if the project is completed, operations. We discuss these risks further below under “Risks Related to Our Businesses Other Than the California Utilities and Our Interest in Oncor – Legal and Regulatory Risks.” In addition, while we have completed the regulatory process for this 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. We experienced significant delays obtaining a necessary export permit from the Mexican government for the ECA LNG Phase 1 liquefaction export project, due in part to government
closures as a result of the COVID-19 pandemic, which resulted in material delays in our ability to reach a final investment decision for this project, and we could experience similar delays or face other hurdles in obtaining, renewing or maintaining all necessary permits and other approvals from the Mexican government for projects in the future. As a result, there is no assurance that the proposed ECA LNG Phase 2 project will be constructed and operated without facing significant regulatory challenges and uncertainties, or at all, which in turn could make project financing, as well as finding or maintaining suitable partners and customers for the ECA LNG Phase 2 project difficult. Finally, we have planned measures to not disrupt operations at the ECA Regas Facility with the construction of the ECA LNG Phase 1 project. However, this is not the case with respect to the construction of the ECA LNG Phase 2 project, which we expect may conflict with the current operations
at the ECA Regas Facility. The ECA Regas Facility currently has long-term regasification contracts for 100% of the regasification facility’s capacity through 2028, making the decision on whether and how to pursue the ECA LNG Phase 2 project dependent in part on whether the investment in a large-scale liquefaction export facility would, over the long term, be more beneficial than continuing to supply regasification services under our existing contracts.
In connection with certain of these LNG export development opportunities, we have entered into or may enter into Heads of Agreements, Interim Project Participation Agreements, MOUs and/or similar arrangements, all of which are or will be nonbinding and do not or will not obligate any of the parties to execute any definitive agreements or participate in any such opportunities. Any decisions by Sempra Energy or our potential counterparties to proceed with a final investment decision
(except with respect to the ECA LNG Phase 1 project, for which a final investment decision has been reached) or binding agreements with respect to our proposed liquefaction export projects will require, among other things, obtaining or maintaining binding 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 LNG export projects are subject to a number of risks and uncertainties, including, among others, the receipt and maintenance of a number of permits and approvals; finding or maintaining suitable partners and customers; obtaining or maintaining financing and incentives; negotiating and completing or maintaining suitable commercial agreements, including equity acquisition and governance agreements, natural gas supply and transportation agreements, LNG sale and purchase agreements and construction contracts (including new EPC contracts for certain
projects); and, except for ECA LNG Phase 1, reaching a final investment decision.
There is no assurance that our proposed LNG export facilities will be completed in accordance with estimated timelines and budgets or at all, and our inability to complete one or more of these facilities or significant delays or cost overruns could have a material adverse effect on our future cash flows, results of operations, financial condition and/or prospects, including the recoverability of all or a substantial portion of the capital costs invested in these projects to date.
Financing Arrangements
We may become involved in various financing arrangements with respect to any of our energy infrastructure projects, some of which could expose us to additional risks. For example, Sempra Energy has provided guarantees for its share of Cameron LNG JV’s financing
obligations related to its Phase 1 facility for a maximum amount of up to $4.0 billion, which 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. Although these performance tests are
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currently underway and we anticipate financial completion will be achieved and the guarantees will be terminated in the first half of 2021, this timing could be delayed, perhaps substantially, if these operational performance tests are not completed due to weather-related events, or other events or factors beyond our control. Any failure to achieve financial completion by September
30, 2021 (unless such date is extended in the event of force majeure) would result in an event of default under Cameron LNG JV’s financing agreements and a potential demand on Sempra Energy’s guarantees. Further, pursuant to the financing agreements, Cameron LNG JV is restricted from making distributions to its project owners, including Sempra LNG, from January 1, 2021 until the earlier of September 30, 2021 and the achievement of financial completion. A delay could materially adversely impact our results of operations and cash flows until financial completion is achieved.
Sempra Energy also has provided a separate guarantee with a maximum exposure to loss of $979 million under the Support Agreement for the benefit of CFIN in connection with a separate financing arrangement intended to return equity to the Cameron LNG JV
project owners. This guarantee terminates upon full repayment of the guaranteed debt by 2039, and the holders of the guarantee are permitted to put the $753 million of guaranteed debt to Sempra Energy on an annual basis and upon the occurrence of certain specified events, including if the guaranteed debt is not paid in accordance with its terms, and may determine to transfer some or all of the guaranteed debt to Sempra Energy at certain specified times.
The loan and other financing agreements related to all of these guarantees contain events of default customary for such financings, and the occurrence of any such default could result in a demand on these guarantees. If we are required to pay some or all of the amounts under these guarantees (or, with respect to the guarantee under the Support Agreement, the guaranteed debt becomes a direct financial obligation as a result of any put or call), any such payments could have a
material adverse effect on our business, results of operations, cash flows, financial condition and/or 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.
Domestic and international hydraulic fracturing operations face political and economic risks and other uncertainties. Several states have adopted or are considering adopting regulations to impose more stringent permitting, public disclosure and 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 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. The current U.S. Administration may have a negative view of hydraulic fracturing practices, which could increase the risk of regulation negatively affecting these operations. 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 (based on Henry Hub pricing) and impact the supply of natural gas to Cameron LNG JV’s Phase 1 project and our other LNG export projects currently in
development. 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 Cameron LNG JV’s Phase 1 facility currently in operation and ECA LNG Phase 1 currently in construction.
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 in an effort 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, rising interest rates that affect financing costs and changes in applicable exchange rates. We may try to mitigate these risks by, among other things, using variable pricing tied to market indices, anticipating 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 fully offset any increases in operating expenses and/or financing costs caused by inflationary pressures, and using these measures could introduce additional risks. 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 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 domestically and internationally) and financial resources
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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, competition for recent pipeline projects
has been intense with numerous bidders competing aggressively for these projects. In addition, Sempra Mexico’s natural gas distribution business faces increased competition now that its former exclusivity period with respect to its distribution zones has expired and other distributors are legally permitted to build and operate natural gas distribution systems and compete to attract customers in the locations where it operates. There is no assurance that we will be successful in bidding for new development opportunities in the U.S. or Mexico. These competitive factors could have a material adverse effect on our business, results of operations, cash flows and/or prospects.
We may not be able to enter into, maintain, extend or replace expiring long-term supply and sales agreements or long-term firm capacity agreements for our projects.
The ECA Regas 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 agreements are intended 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. However, the long-term nature of these agreements also exposes us to risks, including increased credit risks that we discuss below under “Risks Related to Our Businesses Other Than the California Utilities and Our Interest in Oncor – Operational Risks.” In addition, in 2020, the two third-party capacity customers at the ECA Regas Facility, Shell Mexico and Gazprom, asserted a breach of contract by IEnova and a force majeure
event, seeking to terminate these capacity agreements and recover damages. One of these two customers has stopped making payments under its long-term capacity agreement (and IEnova has drawn on the customer’s letter of credit provided as payment security), has submitted a request for arbitration of the dispute and has filed a constitutional challenge related to the dispute, and although the other customer is presently making regular payments under its agreement, it has joined the arbitration proceedings related to the dispute. In addition, one of these customers has commenced legal proceedings in Mexican court seeking modification or rescission of certain material permits for the ECA Regas Facility and ECA LNG. An unfavorable decision with respect to all or any part of these challenges and proceedings, or the potential for an extended dispute, could lead to significant legal and other costs and could materially adversely affect our relationships with these long-term
customers and the reliability of revenues from the ECA Regas Facility. Any such event could have a material adverse effect on our financial condition, results of operations, cash flows and/or prospects.
For certain of our potential liquefaction export projects, definitive sale and purchase agreements have been secured for some of the anticipated nameplate capacity of the applicable facility. These agreements contain conditions of effectiveness, including, for example, our final investment decision for the applicable project within agreed timelines. If these conditions are not satisfied or if these agreements cease to be effective for other reasons, we could be subject to significant competition in securing replacement customers for these projects and we may not be able to do so under favorable terms, in a timely manner or at all. Moreover, some of the anticipated capacity for these potential projects is not currently subject
to definitive customer agreements, and we may not be able to identify suitable customers or negotiate satisfactory sale and purchase agreements for all or a portion of this anticipated capacity in a timely manner or at all. Any such outcome could jeopardize our ability to develop these potential projects and receive an acceptable return on our investments in the projects, which could materially adversely affect our financial condition, 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 export 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, supplies of energy and related products exceed demand and competitive pressures increase, wholesale electricity prices may decline or 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 the performance of counterparties, including with respect to long-term supply, sales and capacity agreements, and any failure by these parties to perform could result in substantial expenses and
business
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disruptions and exposure to commodity price risk and volatility, any of which could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.
Our businesses and the businesses we invest in depend on business partners, customers, suppliers and other counterparties who owe money or commodities as a result of market transactions or other long-term agreements or arrangements to 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. Any efforts to enforce the terms of these agreements or arrangements through legal or other available means could involve significant time and costs and would be unpredictable and susceptible to failure. In addition, many such agreements and arrangements, including the relationships with the applicable counterparties, are important for the conduct and growth of our businesses. Further, we often extend credit to counterparties and customers and, although we perform significant credit analyses prior to extending credit, we may not be able to collect amounts owed to us. The failure of any of our counterparties to perform in accordance with their agreements or arrangements with us could materially adversely affect our businesses, results of operations, cash flows, financial condition and/or prospects.
Our long-term supply, sales and firm
capacity contracts increase our credit risk if our counterparties fail to perform or become unable to meet their contractual obligations. For example, if the counterparties, customers or suppliers to one or more of the key agreements for the ECA Regas Facility or Sempra Mexico’s other long-term capacity agreements for the transportation of natural gas and LPG 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. In addition, for Cameron LNG JV’s Phase 1 project, Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with affiliates of TOTAL SE, Mitsubishi Corporation and Mitsui & Co., Ltd. that collectively 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.
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/or prospects.
Sempra Mexico’s and Sempra LNG’s obligations and those of their suppliers for LNG are contractually subject to suspension or termination for “force majeure” events, which
generally are beyond the control of the parties, and 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 any breach of the agreements, which in each case could have a material adverse effect on our results of operations, cash flows, financial condition and/or prospects.
Sempra Mexico and Sempra LNG engage in JVs or invest in companies in which other equity partners may have or share with us control over the applicable project or investment. We discuss the risks related to these arrangements above under “Risks Related to Our Businesses Other Than the California Utilities and Our Interest in Oncor – Operational Risks.”
We rely on transportation assets and services, much of which we do not own or control, to deliver natural gas
and electricity.
We depend on electric transmission lines, natural gas pipelines and other transportation facilities and services owned and operated by third parties to, among other things:
▪deliver the natural gas and electricity and LPG we sell to wholesale markets or that we use for our natural gas liquefaction export facilities
▪supply natural gas to our gas storage and electric generation facilities
▪provide retail energy services to customers
Sempra Mexico and Sempra LNG also depend on natural gas pipelines to interconnect with the ultimate source or customers of the commodities they are transporting, and also on specialized ships to transport LNG. Sempra
Mexico’s subsidiaries also 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, LNG or LPG supplies at then-current spot market rates, or we could lose customers that may be difficult to replace in competitive market conditions, any of which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.
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Foreign Operations Risks
Our
international businesses and operations expose us to legal, tax, economic, geopolitical, management oversight, foreign currency and inflation risks and challenges.
Overview
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. We also do business with companies based in foreign markets, including particularly our LNG export operations. Developing infrastructure projects, owning energy assets, operating businesses and contracting with companies in foreign jurisdictions subjects us to significant and complex management, security, political, legal, economic and financial risks that vary by country, many of which may differ from and potentially be greater than those associated
with our wholly domestic businesses, including, among others:
▪changes in foreign laws and regulations, including tax, trade and environmental laws and regulations, and U.S. laws and regulations that are related to foreign operations or doing business internationally, including U.S. trade and related policies as we discuss below
▪actions by local regulatory bodies, including setting of rates and tariffs that may be earned by our businesses
▪adverse changes in economic or market conditions, limitations on ownership in foreign countries and inadequate enforcement of regulations
▪risks related to currency exchange and convertibility, including vulnerability to appreciation and
depreciation of foreign currencies against the U.S. dollar, as we discuss below
▪permitting and regulatory compliance
▪adverse rulings by foreign courts or tribunals, challenges to or difficulty obtaining permits or approvals, difficulty enforcing contractual and property rights, differing legal standards for lawsuits or other proceedings, and unsettled property rights and titles in Mexico
▪energy policy reform, including that which may result in adverse changes to and/or difficulty enforcing existing contracts or challenges completing and operating our renewable energy facilities in Mexico, as we discuss below
▪expropriation or theft of assets
▪adverse
changes in the stability of the governments or the economies in the countries in which we operate or do business
▪violence, criminality, or social or political instability
▪compliance with the U.S. Foreign Corrupt Practices Act and similar laws
▪with respect to our non-utility international business activities, changes in the priorities and budgets of international customers, which may be driven by many of the factors listed above, among others
Mexican Government Influence on Economic and Energy Matters
The Mexican government has exercised, and continues to exercise, significant influence over the Mexican economy and energy landscape. Mexican governmental actions
concerning the economy, energy laws and policies 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. In addition, in 2020, certain Mexican governmental agencies issued orders and regulations that would reduce or limit the renewable energy sector’s participation in the country’s energy market. Although many of these measures have
been stayed temporarily as a result of legal complaints filed with applicable Mexican courts, an unfavorable final decision on these complaints, or the potential for an extended dispute, could impact our ability to successfully complete construction of our facilities in Mexico, or to complete them in a timely manner and within expected budgets, may impact our ability to operate our facilities already in service in Mexico and may adversely affect our ability to develop new renewable energy projects in Mexico. Moreover, electricity prices in Mexico are currently subsidized by the Mexican federal government, which could place certain of IEnova’s renewable energy projects at a competitive disadvantage. Additionally, the President of Mexico presented on February 1, 2021 an initiative of amendment of the electrical industry law to include some public policies that are being challenged in court (such as establishing priority
of dispatch for CFE plants over privately owned plants) and other threats to renewable energy. On February 3, 2021, Mexico’s Supreme Court invalidated sections of the Policy for Reliability, Safety, Continuity and Quality of the National Electric System. We cannot predict the impact that the political, social, and judicial
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landscape, including multiparty rule and trial resolutions, will have on the Mexican economy and our business in Mexico. 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 Energy’s consolidated financial statements. We discuss these matters further in Note
16 of the Notes to Consolidated Financial Statements.
Foreign Currency and Inflation
We have significant foreign operations in Mexico, which pose material foreign currency and inflation risks. Exchange and inflation rates with respect to the Mexican peso and fluctuations in those rates may have an impact on our revenue, costs or cash flows from our international operations, which could materially adversely affect our financial condition, results of operations and/or cash flows. 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. It also has 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. We may attempt to hedge material cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments, but these hedges may not successfully achieve our objectives of mitigating earnings volatility that would otherwise occur due to exchange rate fluctuations. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations for entities whose functional currencies are not the U.S. dollar. Moreover, Mexico has experienced periods of high inflation and exchange rate instability in the past, and severe devaluation of the Mexican peso could result in governmental intervention to institute restrictive exchange control policies, as has occurred before in Mexico and other Latin American countries. We discuss our foreign currency
exposure at our Mexican subsidiaries in “Part II – Item 7. MD&A” and “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
U.S. Foreign Policy, including Trade and Related Matters
All our international business activities are sensitive to geo-political uncertainties and related factors, including U.S. foreign policy and the current U.S. position with respect to trade relations and related matters. The last U.S. Administration made substantial changes to or withdrew from trade agreements that affect our operations. For example, the USMCA, which replaced the North American Free Trade Agreement as the principal trade agreement between the U.S., Mexico and Canada, went into force in July 2020, and its long-term impact on our operations remains uncertain. With the current U.S. Administration having taken power in January 2021, the status of
U.S. trade policy and U.S. involvement in international trade agreements going forward remains to be determined and could drastically shift in a manner that increases or mitigates adverse effects on our businesses. The last U.S. Administration also implemented changes to U.S. immigration policy and other policies that impact trade, including increasing tariffs, and the current U.S. Administration has taken steps to reverse some of these changes and could take other material action with respect to these matters. Such policy changes or other actions could adversely affect imports and exports between Mexico and the U.S. and negatively impact the U.S., Mexican and other economies and the companies with whom we conduct business, which could materially adversely affect our business, financial condition, results of operations, cash flows and/or prospects.
Financial Risks
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. The regional and other markets in which we purchase these commodities are competitive and can be subject to significant pricing volatility. Our revenues, results of operations and/or cash flows 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 have 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, change in supply and demand, availability of competitively priced alternative energy sources, commodity production levels and storage capacity, energy and environmental regulations and legislation, and economic and financial market conditions, among other things.
Legal and Regulatory Risks
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Our businesses are subject to various legal actions challenging our property rights and permits, and our properties in Mexico could be subject to expropriation by the Mexican government.
We are engaged in disputes regarding our title to the property in Mexico where our ECA Regas Facility is situated and our proposed ECA LNG liquefaction export
projects are expected to be situated, as we discuss in Note 16 of the Notes to Consolidated Financial Statements. In addition, we may have or seek to obtain long-term leases or rights-of-way from governmental agencies or other third parties to operate our energy infrastructure located on land we do not own for a specific period of time. If we are unable to defend and retain title to the properties we own on which our current and proposed facilities are located, or if we are unable to obtain or retain rights to construct and operate our existing or proposed facilities on the properties we do not own on reasonable financial and other terms, we could lose our rights to occupy and use these properties and the related facilities, which could delay or derail proposed projects, increase our development costs, and result in breaches of one or more permits or contracts related to the affected facilities that could lead to legal costs, fines or penalties. In addition, disputes
regarding any of these properties could make project financing and finding or maintaining suitable partners and customers difficult and could hinder or halt our ability to construct and, if completed, operate the affected facilities or proposed projects. If we are unable to occupy and use the properties and related facilities on which our existing or proposed infrastructure projects are located, it could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.
In addition, IEnova’s business and assets in energy generation, storage, transportation and distribution may be considered by the Mexican government to be a public service or essential for the provision of a public service, in which case these assets and the related business could be subject to expropriation or nationalization, loss of concessions, renegotiation or annulment of existing contracts, and other
similar risks. Any such occurrence could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects.
Risks Related to Our Proposed IEnova Exchange Offerand Our Proposed Transaction Related to Sempra Infrastructure Partners
Our ability to complete our proposed IEnova exchange offer is subject to various conditions and other risks and uncertainties that could cause the transaction to be abandoned, delayed or restructured, which could materially adversely affect us.
In December 2020, we announced our intention to launch a stock-for-stock exchange offer to acquire all outstanding publicly held shares of IEnova. The completion of this transaction is subject to governmental and regulatory consents, approvals and rulings, including from the
SEC, CNBV and Mexican Stock Exchange, and other closing conditions. These and other governmental and regulatory authorities may not provide the consents, approvals and rulings that are needed to complete this transaction or could seek to block or challenge the transaction. In addition, other closing conditions to consummate the proposed transaction may not be satisfied. For example, the completion of the exchange offer is subject to the condition that the IEnova shares validly tendered and not withdrawn, together with all IEnova shares that we directly or indirectly own, represent no less than 95% of all of IEnova’s outstanding ordinary shares, determined on the basis of all outstanding ordinary shares and on a fully diluted basis. Although we have the right to waive this condition, there is no assurance that we would do so, and we have no control over the level of participation in the exchange offer by IEnova’s public shareholders. As a result, we may decide not to
complete the exchange offer if this condition is not satisfied. If the required consents, approvals and rulings are not received or the other closing conditions are not satisfied or waived, or if any of the foregoing is not achieved in a timely manner or on satisfactory terms, then the proposed exchange offer may be abandoned and our results of operations, cash flows, financial condition and/or prospects could be materially adversely affected.
Our ability to complete the proposed exchange offer is subject to a number of other risks and uncertainties, many of which are not in our control, including, among others, if another party were to offer to acquire the publicly held shares of IEnova on terms that are more favorable than the terms we offer, as well as industry and market conditions. These risks and uncertainties could alter the proposed structure of the transaction or negatively affect our ability to complete the transaction
in a timely manner or at all.
The occurrence of any of the foregoing risks individually or in combination could lead to the abandonment, delay or restructuring of the proposed exchange offer, in which case we would not be able to realize the potential benefits of the transaction but would still be required to pay the substantial costs incurred in connection with pursuing it, which could materially adversely affect our results of operations, cash flows, financial condition and/or prospects and the market value of our common stock, preferred stock and debt securities.
The proposed exchange offer, if completed, may not have the positive effects we anticipate, which may negatively affect the market price of our common stock, preferred stock and debt securities.
62
We
anticipate that the proposed exchange offer, if completed on the currently contemplated terms, will, over the long-term, have a positive impact on our cash flows, results of operations and financial condition. This expectation is based on current market conditions and is subject to a number of assumptions, estimates, projections and other uncertainties, including assumptions about the results of operations of IEnova after the proposed transaction and the costs to us to complete the transaction. If the transaction is completed, we may find that IEnova does not perform in accordance with our expectations for a number of reasons, including those we discuss above under “Risks Related to Our Businesses Other Than the California Utilities and Our Interest in Oncor.” In addition, we may fail to realize some or any of the benefits we expect from the transaction, we may incur material additional transaction costs, and we may be subject to other factors that cause our preliminary
estimates to be incorrect. As a result, there is no assurance that the proposed exchange offer will positively impact our cash flows, results of operations, financial condition or other aspects of our performance, and it is possible that the transaction may have an adverse effect, which could be material, on our results of operations, cash flows, financial condition and/or prospects, any of which could materially adversely affect the market price of our common stock, preferred stock and debt securities.
We expect to issue shares of our common stock in the proposed exchange offer, which would dilute the voting interests and could dilute the economic interests of our current shareholders and may adversely affect the market value of our common stock and preferred stock.
In the proposed transaction, we intend to offer to acquire up to 100% of the publicly held shares of IEnova in exchange
for shares of our common stock at an exchange ratio of 0.0313 shares of our common stock for each one IEnova ordinary share, which exchange ratio remains subject to approval by the Sempra Energy board of directors. If all publicly held shares of IEnova are validly tendered into and not withdrawn from this exchange offer, and no IEnova shares are issued after February 22, 2021, then up to 13,560,497 shares of our common stock would be issued in the exchange offer. Although the exact number of shares of our common stock we may issue is uncertain and subject to a number of factors, many of which are beyond our control, and we may in fact issue fewer shares than anticipated, the issuance of a substantial number of additional shares of our common stock in this exchange offer would dilute the voting interests of our shareholders. In addition, the issuance of additional shares of our common stock without a commensurate increase
in our consolidated earnings would decrease our EPS. Any of the foregoing may have a material adverse effect on the market value of our common stock.
The proposed exchange offer, if completed, would subject us to additional regulation and liability in Mexico.
If we are able to complete the proposed exchange offer, we intend to list our common stock for trading on the Mexican Stock Exchange and register our common stock with the CNBV. Such listing and registration would subject us to additional filing and other requirements in Mexico that could involve significant costs and materially distract our personnel from their other responsibilities. In addition, if we become an issuer with stock registered in Mexico, the CNBV, as the Mexican securities market regulator, would have surveillance authority over Sempra Energy. This means that the CNBV would have the authority to make inspections
of Sempra Energy’s business, primarily in the form of requests for information and documents; impose fines or other penalties or sanctions for violations of Mexican securities laws and regulations; and seek criminal liability for actions conducted or with effects in Mexico. In addition, Sempra Energy’s directors and officers would be subject to additional liability and trading restrictions with respect to their shares of Sempra Energy common stock under the securities laws and regulations in Mexico, which could make it more difficult to attract, recruit and retain qualified people for these positions. The occurrence of any of these risks could materially adversely affect our business, results of operations, cash flows, financial condition and/or prospects.
In addition, although we intend to delist IEnova’s shares from the Mexican Stock Exchange and cancel the registration of these shares with the CNBV if the proposed exchange
offer is completed, such delisting and deregistration are subject to a number of requirements under applicable Mexican law and regulations, including the affirmative vote of no less than 95% of IEnova’s ordinary shares at a shareholders’ meeting held for that purpose. If we are not able to acquire sufficient shares in the exchange offer to satisfy this threshold, then we likely would not be able to obtain the votes necessary to effect such delisting and deregistration. In that case, both Sempra Energy and IEnova would be subject to regulation and liability as listed companies under Mexican securities laws after the exchange offer is completed, which would involve significant burdens on both companies that could negatively affect our businesses, results of operations, cash flows and/or financial condition.
Our proposed transaction related to Sempra Infrastructure Partners is subject to a number of risks and uncertainties.
In
December 2020, we announced our intention to sell NCI in Sempra Infrastructure Partners, which represents the combined businesses of Sempra LNG and IEnova. Our ability to complete this transaction is subject to a number of risks, including, among others, the ability to identify a suitable partner to purchase such NCI; negotiate the terms of equity sale, shareholder and other governance agreements with such partner; and obtain governmental, regulatory and third-party consents and approvals and satisfy any other closing conditions to complete this transaction. Although the structure and terms of this transaction remain to be
63
determined, the governmental and regulatory authorities with jurisdiction over the transaction could seek to block or challenge it or could
impose requirements or obligations as conditions to its approval. If any of these circumstances were to occur, or if we are not able to achieve all of the foregoing in a timely manner or on satisfactory terms, then the proposed transaction may be abandoned and our prospects could be materially adversely affected.
Moreover, even if we are able to complete this transaction, it may not result in the benefits we presently anticipate. Although we expect that this transaction could, over the long-term, have a positive impact on our cash flows, results of operations and financial condition, this expectation is based on a number of assumptions, estimates, projections and other uncertainties about, among other things, the terms of the sale of NCI in Sempra Infrastructure Partners, the identity of the buyer of such NCI, the shareholder and other governance arrangements we make with such buyer, the costs to us to complete this transaction,
the results of operations of Sempra LNG and IEnova after the proposed transaction, and other factors beyond our control. In light of the early stage of this proposed transaction, there are significant uncertainties regarding its ultimate impact on our businesses, and our current expectations about the potential benefits of this transaction could turn out to be wrong.
The proposed sale of NCI in Sempra Infrastructure Partners will reduce our ownership interest in Sempra Infrastructure Partners. Any decrease in our ownership of Sempra Infrastructure Partners would also decrease our share of the cash flows, profits and other benefits these businesses currently or may in the future produce, which could materially adversely affect our results of operations, cash flows, financial condition and/or prospects.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
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 “Part I – Item 1. Business” and Note 1 of the Notes to Consolidated Financial Statements.
ITEM
3. LEGAL PROCEEDINGS
We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters described in Notes 15 and 16 of the Notes to Consolidated Financial Statements, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity.”
ITEM
4. MINE SAFETY DISCLOSURES
Not applicable.
64
PART II.
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 NYSE under the ticker symbol SRE. At February 22, 2021, there were approximately 23,345 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.
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
On
July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $2 billion or amounts spent to purchase no more than 25 million shares. This repurchase authorization was publicly announced on August 5, 2020 and has no expiration date. No shares have been repurchased under this authorization.
We may also, from time to time, purchase shares of our common stock to which participants would otherwise be entitled from LTIP participants who elect to sell a sufficient number of shares in connection with the vesting of RSUs and stock options in order to satisfy minimum statutory tax withholding requirements.
ITEM
6. SELECTED FINANCIAL DATA
FIVE-YEAR SUMMARIES
The following tables present selected financial data of Sempra Energy, SDG&E and SoCalGas for the five years ended December 31, 2020. The data is derived from the audited consolidated financial statements of each company. You should read this information in conjunction with “Part II – Item 7. MD&A” and the consolidated financial statements and notes contained in this annual report on Form 10-K.
65
FIVE-YEAR
SUMMARY OF SELECTED FINANCIAL DATA – SEMPRA ENERGY CONSOLIDATED
(In millions, except per share amounts)
At December 31 or for the years then ended
2020
2019
2018
2017
2016
Revenues:
Utilities
Natural
gas
$
5,411
$
5,185
$
4,540
$
4,361
$
4,050
Electric
4,614
4,263
3,999
3,929
3,748
Energy-related
businesses
1,345
1,381
1,563
1,350
829
Total revenues
$
11,370
$
10,829
$
10,102
$
9,640
$
8,627
Income
from continuing operations, net of income tax
$
2,255
$
1,999
$
938
$
382
$
1,292
Income (loss) from discontinued operations, net of income tax
1,850
363
188
(31)
227
Net
income
4,105
2,362
1,126
351
1,519
Earnings attributable to noncontrolling interests
(172)
(164)
(76)
(94)
(148)
Preferred
dividends
(168)
(142)
(125)
—
—
Preferred dividends of subsidiary
(1)
(1)
(1)
(1)
(1)
Earnings
attributable to common shares
$
3,764
$
2,055
$
924
$
256
$
1,370
Basic
EPS:
Earnings from continuing operations
$
6.61
$
6.22
$
2.86
$
1.25
$
4.66
Earnings
(losses) from discontinued operations
$
6.32
$
1.18
$
0.59
$
(0.23)
$
0.82
Earnings
$
12.93
$
7.40
$
3.45
$
1.02
$
5.48
Diluted
EPS:
Earnings from continuing operations
$
6.58
$
6.13
$
2.84
$
1.24
$
4.65
Earnings
(losses) from discontinued operations
$
6.30
$
1.16
$
0.58
$
(0.23)
$
0.81
Earnings
$
12.88
$
7.29
$
3.42
$
1.01
$
5.46
Dividends
declared per common share
$
4.18
$
3.87
$
3.58
$
3.29
$
3.02
Effective income tax rate
14
%
18
%
(10)
%
73
%
22
%
Weighted-average
rate base:
SDG&E
$
11,109
$
10,467
$
9,619
$
8,549
$
8,019
SoCalGas
$
8,228
$
7,401
$
6,413
$
5,493
$
4,775
AT
DECEMBER 31
Current assets
$
4,511
$
3,339
$
3,645
$
3,341
$
3,110
Total
assets
$
66,623
$
65,665
$
60,638
$
50,454
$
47,786
Current liabilities
$
6,839
$
9,150
$
7,523
$
6,635
$
5,927
Short-term
debt(1)
$
2,425
$
5,031
$
3,668
$
2,790
$
2,542
Long-term debt and finance leases (excludes current portion)(2)
$
21,781
$
20,785
$
20,903
$
15,829
$
13,865
Sempra
Energy shareholders’ equity
$
23,373
$
19,929
$
17,138
$
12,670
$
12,951
Common shares outstanding
288.5
291.7
273.8
251.4
250.2
Book
value per common share
$
70.11
$
60.58
$
54.35
$
50.40
$
51.77
(1) Includes long-term debt due within one year and current portion of finance lease obligations. Excludes discontinued operations.
(2)Excludes
discontinued operations.
In 2020, SoCalGas recorded charges of $307 million ($233 million after tax) in Aliso Canyon Litigation and Regulatory Matters on the SoCalGas and Sempra Energy Consolidated Statements of Operations related to settlement discussions in connection with civil litigation and regulatory matters. We discuss these matters in Note 16 of the Notes to Consolidated Financial Statements.
In 2020, we completed the sale of our equity interests in our Peruvian businesses for cash proceeds of $3,549 million, net of transaction costs and as adjusted for post-closing adjustments, and recorded a pretax gain of $2,271 million ($1,499 million after tax) in discontinued operations. Also in 2020, we completed the sale of our equity interests in our Chilean businesses for cash proceeds of $2,216 million, net of transaction costs and as adjusted
for post-closing adjustments, and recorded a pretax gain of $628 million ($248 million after tax) in discontinued operations. We discuss discontinued operations in Note 5 of the Notes to Consolidated Financial Statements.
66
In 2020, we recorded a charge of $100 million in Equity Earnings on Sempra Energy’s Consolidated Statement of Operations for losses from our investment in RBS Sempra Commodities. We discuss the charge further in Note 16 of the Notes to Consolidated Financial Statements.
In 2020, Sempra Energy completed a registered public offering of our series C preferred stock. This offering provided net proceeds of $889 million. We used the net proceeds for working capital and other general corporate purposes, including
the repayment of indebtedness.
In 2020, Sempra Energy entered into and completed an ASR program under which we paid $500 million to repurchase 4,089,375 shares of our common stock at an average price of $122.27 per share.
In 2019, Sempra Renewables completed the sale of its remaining U.S. wind assets and investments and recognized a pretax gain on sale of $61 million ($45 million after tax and NCI). In 2018, Sempra Renewables completed the sale of its 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 sales and related gains in Note 5 of the Notes to Consolidated Financial Statements.
In 2018, we recorded impairment charges of $1.1 billion ($629 million after tax and NCI) at
Sempra LNG, $200 million ($145 million after tax) at Sempra Renewables and $65 million at Parent and other. We discuss the impairments in Notes 5, 6 and 12 of the Notes to Consolidated Financial Statements.
In 2018, Sempra Energy completed registered public offerings of our common stock (including shares offered pursuant to forward sale agreements), series A preferred stock, series B preferred stock and long-term debt. These offerings, including settlement of the forward sale agreements, provided total net proceeds of approximately $4.5 billion in equity and $4.9 billion in debt. A portion of these proceeds were used to partially fund the acquisition of an indirect, 100% interest in Oncor Holdings, which we account for as an equity method investment. We discuss the acquisition and equity method investment further in Notes 5 and 6 of the Notes to Consolidated Financial Statements.
In
2017, Sempra Energy’s income tax expense included $870 million related to the impact of the TCJA.
In 2017, we recorded a charge of $208 million (after tax) for the write-off of SDG&E’s wildfire regulatory asset.
In 2017 and 2016, Sempra Mexico recognized impairment charges of $47 million (after NCI) and $90 million (after tax and NCI), respectively, related to assets held for sale at TdM.
In 2016, we recorded a $350 million (after tax and NCI) noncash gain associated with the remeasurement of Sempra Mexico’s equity interest in IEnova Pipelines.
In 2016, IEnova completed a private offering in the U.S. and outside of Mexico and a concurrent public offering in Mexico of common stock.
We discuss litigation and other contingencies in Note 16 of the Notes
to Consolidated Financial Statements.
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FIVE-YEAR SUMMARIES OF SELECTED FINANCIAL DATA –
SDG&E AND SOCALGAS
(Dollars in millions)
At December 31 or for the years then ended
2020
2019
2018
2017
2016
SDG&E:
Statement
of Operations Data:
Operating revenues
$
5,313
$
4,925
$
4,568
$
4,476
$
4,253
Operating
income
1,373
1,313
1,010
709
976
Earnings attributable to common shares
824
767
669
407
570
Balance
Sheet Data:
Total assets
$
22,311
$
20,560
$
19,225
$
17,844
$
17,719
Short-term
debt(1)
611
136
372
473
191
Long-term debt and finance leases (excludes current portion)
6,866
6,306
6,138
5,335
4,658
SDG&E
shareholder’s equity
7,730
7,100
6,015
5,598
5,641
SoCalGas:
Statement
of Operations Data:
Operating revenues
$
4,748
$
4,525
$
3,962
$
3,785
$
3,471
Operating
income
785
956
591
627
551
Dividends on preferred stock
1
1
1
1
1
Earnings
attributable to common shares
504
641
400
396
349
Balance Sheet Data:
Total
assets
$
18,460
$
17,077
$
15,389
$
14,159
$
13,424
Short-term debt(1)
123
636
259
617
62
Long-term
debt and finance leases (excludes current portion)
4,763
3,788
3,427
2,485
2,982
SoCalGas shareholders’ equity
5,144
4,748
4,258
3,907
3,510
(1)Includes
long-term debt due within one year and current portion of finance lease obligations.
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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 our mission to be North America’s premier energy infrastructure company.
Our 2020 operational and financial results reflect our focus on executing this strategy:
▪We completed the sales of our South American businesses
▪We achieved full commercial operations at Cameron LNG JV Phase 1
▪We reached a final investment decision for ECA LNG Phase 1
▪We executed well on our planned capital expenditures
Our South American businesses and certain activities associated with those businesses are presented as 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:
▪Overall results of operations of Sempra Energy Consolidated;
▪Segment
results;
▪Significant changes in revenues, costs and earnings; and
▪Impact of foreign currency and inflation rates on our results of operations.
OVERALL RESULTS OF OPERATIONS OF SEMPRA ENERGY CONSOLIDATED
In 2020 compared to 2019, our earnings increased by $1,709 million to $3,764 million and our diluted EPS increased by $5.59 to $12.88. In 2019 compared to 2018, our earnings increased by $1,131 million to $2,055 million and our diluted EPS increased by $3.87 to $7.29. The change in diluted EPS for 2020 and 2019 included decreases of $(0.46) and $(0.33), 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
This section presents earnings (losses) by Sempra Energy segment, as well as Parent and other and discontinued operations, and a related discussion of the changes in segment earnings (losses). Throughout the MD&A, our reference to earnings represents earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted, and before NCI, where applicable.
(1)Includes intercompany eliminations recorded in consolidation and certain corporate costs.
SDG&E
The increase in earnings of $57 million (7%) in 2020 compared to 2019 was primarily due to:
▪$62
million due to the release of a regulatory liability in 2020 related to 2016-2018 forecasting differences that are not subject to tracking in the income tax expense memorandum account, which we discuss in Note 4 of the Notes to Consolidated Financial Statements;
▪$52 million higher electric transmission margin, including an increase in authorized ROE and the following impacts from the March 2020 FERC-approved TO5 settlement:
◦$18 million to conclude a rate base matter, and
◦$9 million favorable impact from the retroactive application of the final TO5 settlement for 2019;
▪$23 million higher AFUDC equity; and
▪$16
million higher income tax benefits from flow-through items; offset by
▪$44 million expected to be refunded to customers and a fine related to the Energy Efficiency Program inquiry, which we discuss in Note 4 of the Notes to Consolidated Financial Statements;
▪$31 million income tax benefit in 2019 from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed to be allocated to shareholders in a January 2019 decision;
▪$13 million higher amortization and accretion of the Wildfire Fund asset and liability, respectively; and
▪$12 million higher net interest expense.
The
increase in earnings of $98 million (15%) in 2019 compared to 2018 was primarily due to:
▪$71 million higher CPUC base operating margin authorized for 2019, net of operating expenses;
▪$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
▪$11 million higher margin from electric transmission operations, net of a FERC formulaic rate adjustment benefit in 2018; offset by
▪$10 million amortization of the Wildfire Fund asset.
SoCalGas
The
decrease in earnings of $137 million (21%) in 2020 compared to 2019 was primarily due to:
▪$233 million from impacts associated with Aliso Canyon natural gas storage facility litigation and regulatory matters;
▪$38 million income tax benefit in 2019 from the impact of the January 2019 CPUC decision allocating certain excess deferred income tax balances to shareholders; and
▪$12 million higher net interest expense; offset by
▪$64 million due to the release of a regulatory liability in 2020 related to 2016-2018 income tax expense forecasting differences;
▪$29 million higher CPUC
base operating margin authorized for 2020, net of operating expenses;
▪$21 million impairment of non-utility native gas assets in 2019;
▪$10 million higher income tax benefits from flow-through items; and
▪$8 million in penalties in 2019 related to the SoCalGas billing practices OII.
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The increase in earnings of $241 million in 2019 compared to 2018 was primarily due to:
▪$216 million higher CPUC base operating margin authorized for 2019, net of operating expenses;
▪$38
million income tax benefit from the impact of the January 2019 CPUC decision allocating certain excess deferred income tax balances to shareholders;
▪$22 million from impacts associated with Aliso Canyon natural gas storage facility litigation in 2018; and
▪$14 million higher income tax benefits from flow-through items; offset by
▪$21 million impairment of non-utility native gas assets in 2019;
▪$18 million higher net interest expense; and
▪$8 million penalties in 2019 related to the SoCalGas billing practices OII.
Sempra Texas Utilities
The
increase in earnings of $51 million (10%) in 2020 compared to 2019 was primarily due to higher equity earnings from Oncor Holdings driven by:
▪increased revenues from rate updates to reflect increases in invested capital and customer growth;
▪the impact of Oncor’s acquisition of InfraREIT in May 2019; and
▪higher AFUDC equity; offset by
▪unfavorable weather and increased operating costs and expenses attributable to invested capital.
The increase in earnings of $157 million (42%) in 2019 compared to 2018 primarily represented 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, offset by higher operating costs.
Sempra Mexico
Because Ecogas, our natural gas distribution utility in Mexico, uses the local currency as its functional currency, its revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra Energy’s results of operations. Prior year amounts used in the variances discussed below are as adjusted for the difference in foreign currency translation rates between years. We discuss these and other foreign currency effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.”
The increase in earnings of $6 million (2%) in 2020 compared to 2019 was primarily
due to:
▪$69 million favorable impact from foreign currency and inflation effects, net of foreign currency derivatives effects, comprised of:
◦in 2020, $51 million favorable foreign currency and inflation effects, offset by a $39 million loss from foreign currency derivatives, and
◦in 2019, $86 million unfavorable foreign currency and inflation effects, offset by a $29 million gain from foreign currency derivatives; and
▪$33 million higher earnings primarily due to the start of commercial operations of the Sur de Texas-Tuxpan marine pipeline at IMG JV in September 2019; offset by
▪$165
million earnings attributable to NCI at IEnova in 2020 compared to $122 million earnings in 2019;
▪$22 million higher net interest expense;
▪$21 million lower earnings at the Guaymas-El Oro segment of the Sonora pipeline primarily from force majeure payments that ended in August 2019; and
▪$13 million lower earnings at TdM primarily due to scheduled major maintenance in the fourth quarter of 2020.
The increase in earnings of $16 million (7%) in 2019 compared to 2018 was primarily due to:
▪$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;
▪$16
million lower income tax expense in 2019 primarily from a two-year tax abatement that expired in 2020; and
▪$122 million earnings attributable to NCI at IEnova in 2019 compared to $132 million earnings in 2018; offset by
▪$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:
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◦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.
Sempra LNG
Earnings of $320 million in 2020 compared to losses of $6 million in 2019 were primarily due to:
▪$284 million higher equity earnings from Cameron LNG JV primarily due to commencement of Phase 1 commercial operations; and
▪$41 million higher earnings from Sempra LNG’s marketing operations primarily driven by changes in natural gas prices.
The
decrease in losses of $611 million in 2019 compared to 2018 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.
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 compared to 2018 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.
Parent
and Other
The increase in losses of $47 million (9%) in 2020 compared to 2019 was primarily due to:
▪$100 million equity losses from our investment in RBS Sempra Commodities to settle pending tax matters and related legal costs, which we discuss in Note 16 of the Notes to Consolidated Financial Statements;
▪$26 million higher preferred dividends due to the issuance of series C preferred stock in June 2020;
▪$9 million lower net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation obligations, net of deferred compensation expenses; offset by
▪$36
million lower net interest expense;
▪$18 million higher income tax benefit primarily due to:
◦$26 million income tax benefit in 2020 compared to $7 million income tax expense in 2019 from changes to a valuation allowance against certain tax credit carryforwards, and
◦$11 million income tax benefit in 2020 compared to $2 million income tax expense in 2019 related to share-based compensation, offset by
◦$24 million consolidated California state income tax expense in 2020 associated with income from our investments in Sempra LNG entities, and
◦$10 million income tax benefit in 2019
from a reduction in a valuation allowance against certain NOL carryforwards as a result of our decision to sell our South American businesses; and
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▪$8 million decrease in losses from foreign currency derivatives used to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sale of our South American businesses.
The decrease in losses of $105 million (17%) in 2019 compared to 2018 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 preferred 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.
Discontinued Operations
Discontinued operations that were previously in our Sempra South American Utilities segment include our former 100% interest in Chilquinta Energía in Chile, our former 83.6% interest in Luz del Sur in Peru and our former interests in two energy-services companies, Tecnored and Tecsur, which provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, respectively, as well as third parties. Discontinued operations also include activities, mainly income taxes related to the South American businesses, that were previously included in the holding company of the South American businesses at Parent
and other.
As we discuss in Note 5 of the Notes to Consolidated Financial Statements, we completed the sales of our South American businesses in the second quarter of 2020. In April 2020, we sold our equity interests in our Peruvian businesses, including our 83.6% interest in Luz del Sur and our interest in Tecsur, for cash proceeds of $3,549 million, net of transaction costs and as adjusted for post-closing adjustments, and in June 2020, we sold our equity interests in our Chilean businesses, including our 100% interest in Chilquinta Energía and Tecnored and our 50% interest in Eletrans, for cash proceeds of $2,216 million, net of transaction costs and as adjusted for post-closing adjustments.
The increase in earnings from our discontinued operations of $1,512 million in 2020 compared to 2019 was primarily due to:
▪$1,499
million after-tax gain on the sale of our Peruvian businesses;
▪$248 million after-tax gain on the sale of our Chilean businesses; and
▪$7 million income tax benefit in 2020 compared to $51 million income tax expense in 2019 related to changes in outside basis differences from earnings and foreign currency effects since the January 25, 2019 approval of our plan to sell our South American businesses; offset by
▪$201 million lower operational earnings mainly as a result of the sales of our Peruvian and Chilean businesses; and
▪$89 million income tax benefit in 2019 related to outside basis differences
existing as of January 25, 2019.
The increase in earnings of $172 million in 2019 compared to 2018 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.
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.
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Utilities
Revenues and Cost of Sales
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.
▪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 program expenditures and other costs authorized by the CPUC, or “refundable programs.”
Because changes in SoCalGas’ and SDG&E’s cost of natural gas and/or electricity are recovered in rates, changes in these costs are offset in
the changes in revenues and therefore do not impact earnings. In addition to the changes in cost or market prices, natural gas or electric revenues recorded during a period are impacted by 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.
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The table below summarizes utilities revenues and cost of sales.
(1)
Excludes depreciation and amortization, which are presented separately on the Sempra Energy, SDG&E and SoCalGas Consolidated Statements of Operations.
Natural Gas Revenues and Cost of Natural Gas
The table below summarizes the average cost of natural gas sold by the California Utilities and included in Cost of Natural Gas on the Consolidated Statements of Operations. The average cost of natural gas sold at each utility is impacted by market prices, as well as transportation, tariff and other charges.
In
2020 compared to 2019, our natural gas revenues increased by $226 million (4%) to $5.4 billion primarily due to:
▪$223 million increase at SoCalGas, which included:
◦$198 million higher CPUC-authorized revenues,
◦$144 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M, and
◦$84 million due to the release of a regulatory liability in 2020 related to 2016-2018 income tax expense forecasting differences, offset by
◦$194 million decrease in cost of natural gas sold, which we discuss below, and
◦$19
million lower non-service component of net periodic benefit cost in 2020, which fully offsets in Other (Expense) Income, Net; and
▪$36 million increase at SDG&E, which included:
◦$23 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M,
◦$15 million higher CPUC-authorized revenues, and
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◦$6 million due to the release of a regulatory liability in 2020 related to 2016-2018 income tax expense forecasting differences, offset by
◦$14
million decrease in cost of natural gas sold, which we discuss below; offset by
▪$15 million decrease at Sempra Mexico primarily due to foreign currency effects and a regulatory rate adjustment.
In 2019 compared to 2018, 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 CPUC-authorized revenue in 2019,
◦$105 million higher recovery of costs associated with 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 (Expense) 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.
Our cost of natural gas decreased by $214 million (19%) to $925 million in 2020 compared to 2019 primarily due to:
▪$194 million decrease at SoCalGas, including $143 million from lower average natural gas prices and $51 million from lower volumes driven primarily by weather; and
▪$14 million decrease at SDG&E, including $7 million from lower average natural gas prices and $7 million from lower volumes driven primarily by weather.
Our cost of natural gas decreased by $69 million (6%) to $1.1 billion in 2019 compared to 2018 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.
Electric Revenues and Cost of Electric Fuel and Purchased Power
Our electric revenues, substantially all of which are at SDG&E, increased by $351 million (8%) to $4.6 billion in 2020 compared to 2019 primarily due to:
▪$242 million higher recovery
of costs associated with refundable programs, which revenues are offset in O&M;
▪$112 million higher revenues from transmission operations, including an increase in authorized ROE and the following impacts related to the March 2020 FERC-approved TO5 settlement:
◦$26 million to settle a rate base matter, and
◦$12 million favorable impact from the retroactive application of the final TO5 settlement for 2019;
▪$77 million due to the release of a regulatory liability in 2020 related to 2016-2018 income tax expense forecasting differences;
▪$35 million higher CPUC-authorized revenues; and
▪$19
million higher revenues associated with SDG&E’s wildfire mitigation plan; offset by
▪$55 million lower cost of electric fuel and purchased power, which we discuss below; and
▪$51 million expected to be refunded to customers related to the Energy Efficiency Program inquiry.
In 2019 compared to 2018, our electric revenues increased by $264 million (7%) to $4.3 billion, primarily attributable to SDG&E, primarily due to:
▪$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;
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▪$34 million higher recovery of costs associated with 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.
Our
utility cost of electric fuel and purchased power, substantially all of which is at SDG&E, decreased by $1 million remaining at $1.2 billion in 2020 compared to 2019 primarily due to:
▪$55 million lower recoverable cost of electric fuel and purchased power primarily due to a decrease in residential demand mainly from an increase in rooftop solar adoption; offset by
▪$52 million associated with Otay Mesa VIE, which we deconsolidated in August 2019.
Our utility cost of electric fuel and purchased power decreased by $170 million (13%) to $1.2 billion in 2019 compared to 2018, primarily attributable to SDG&E, primarily due to:
▪$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.
Energy-Related Businesses: Revenues and Cost of Sales
The table below shows revenues and cost of sales for our energy-related businesses.
ENERGY-RELATED
BUSINESSES: REVENUES AND COST OF SALES
(1) Includes
eliminations of intercompany activity.
(2)Excludes depreciation and amortization, which are presented separately on the Sempra Energy Consolidated Statements of Operations.
Revenues from our energy-related businesses decreased by $36 million (3%) to $1.3 billion in 2020 compared to 2019 primarily due to:
▪$104 million decrease at Sempra Mexico primarily due to:
◦$59 million from the marketing business primarily due to lower natural gas prices and volumes,
◦$37
million lower revenues from TdM mainly due to lower volumes, offset by higher power prices, and
◦$21 million lower transportation revenues primarily from force majeure payments that ended in August 2019 with respect to the Guaymas-El Oro segment of the Sonora pipeline; and
▪$36 million decrease at Sempra LNG primarily due to:
◦$87 million decrease in revenues from LNG marketing operations primarily from lower natural gas sales to Sempra Mexico mainly as a result of lower volumes and natural gas prices, and from lower diversion revenues due to lower natural gas prices, and
◦$18 million lower revenues from the expiration of capacity release contracts in the fourth quarter of
2019, offset by
◦$70 million increase from natural gas marketing operations primarily due to changes in natural gas prices; offset by
▪$114 million increase primarily from lower intercompany eliminations associated with sales between Sempra LNG and Sempra Mexico.
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In 2019 compared to 2018, revenues from our energy-related businesses decreased by $182 million (12%) to $1.4 billion primarily due to:
▪$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.
The cost of sales for our energy-related businesses decreased by $68 million (20%) to $276 million in 2020 compared to 2019 primarily due to:
▪$90 million decrease at Sempra Mexico mainly associated with lower revenues from the marketing business and from TdM as a result of lower volumes and natural gas prices; and
▪$81 million decrease at Sempra LNG mainly from natural gas marketing activities primarily due to lower natural gas purchases; offset by
▪$103 million increase primarily from lower intercompany eliminations associated with sales between Sempra LNG and Sempra Mexico.
The cost of sales for our energy-related
businesses in 2019 was comparable to 2018.
(1) Excludes impairment losses, which we discuss below.
(2) Includes
eliminations of intercompany activity.
Our O&M increased by $474 million (14%) to $3.9 billion in 2020 compared to 2019 primarily due to:
▪$279 million increase at SDG&E, primarily due to:
◦$265 million higher expenses associated with refundable programs for which costs incurred are recovered in revenue (refundable program expenses), and
◦$18 million higher amortization of the Wildfire Fund asset and accretion of the Wildfire Fund obligation; and
▪$249 million increase
at SoCalGas, primarily due to:
◦$144 million higher expenses associated with refundable programs, and
◦$105 million higher non-refundable operating costs, including labor, purchased materials and services, and administrative and support costs; offset by
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▪$62 million decrease at Parent and other primarily from lower deferred compensation expense and retained operating costs; and
▪$18 million decrease at Sempra Renewables primarily due to lower general and administrative
and other costs due to the wind-down of the business in 2019.
Our O&M increased by $316 million (10%) to $3.5 billion in 2019 compared to 2018 primarily due to:
▪$167 million increase at SoCalGas, primarily due to:
◦$105 million higher expenses associated with refundable programs, and
◦$57 million higher non-refundable operating costs, including labor, contract services and administrative and support costs;
▪$117 million increase at SDG&E, primarily due to:
◦$147 million higher expenses associated with refundable programs, including $112 million
of 2019 liability insurance premium costs that are now balanced in revenue, and
◦$13 million amortization of the Wildfire Fund asset and accretion of the Wildfire Fund obligation, 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.
Aliso Canyon Litigation and Regulatory Matters
In 2020, SoCalGas recorded a charge of $307 million in Aliso Canyon Litigation and Regulatory Matters related to settlement discussions in connection with civil litigation and regulatory matters associated with the Leak, which we describe in Note 16 of the Notes to Consolidated Financial Statements.
Impairment Losses
In September 2019, SoCalGas recognized a $29 million
impairment loss related to non-utility native gas assets. In September 2019, SDG&E and SoCalGas recognized impairment losses of $6 million and $8 million, respectively, for certain disallowed capital costs in the 2019 GRC FD. 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.
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. 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.
Other (Expense) Income, Net
As part of our central risk management function,
we may 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 (Expense) 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 utilized foreign currency derivatives to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sales of our operations in Peruand Chile, respectively. We discuss policies governing our risk management below in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Other expense, net, was $48 million in
2020 compared to other income, net, of $77 million in 2019. The change was primarily due to:
▪$92 million net losses in 2020 from interest rate and foreign exchange instruments and foreign currency transactions compared to net gains of $55 million in 2019 primarily due to:
◦$53 million losses in 2020 compared to $40 million gains in 2019 on foreign currency derivatives as a result of fluctuation of the Mexican peso, and
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◦$42 million losses in 2020 compared to $30 million gains in 2019 on a Mexican peso-denominated loan to IMG JV, which is offset in Equity Earnings; offset
by
◦$17 million gains in 2020 compared to $9 million losses in 2019 on other foreign currency transactional effects;
▪$20 million lower investment gains in 2020 on dedicated assets in support of our executive retirement and deferred compensation plans; and
▪$6 million fine at SDG&E related to the Energy Efficiency Program inquiry; offset by
▪$34 million higher AFUDC equity, including $23 million at SDG&E and $7 million at SoCalGas;
▪$30 million lower non-service component of net periodic benefit cost in 2020;
▪$8
million increase in regulatory interest at the California Utilities due to the release of a regulatory liability in 2020 related to 2016-2018 income tax expense forecasting differences; and
▪$8 million in penalties in 2019 related to the SoCalGas billing practices OII.
In 2019 compared to 2018, other income, net, increased by $19 million (33%) to $77 million primarily due to:
▪$61 million investment gains in 2019 compared to $6 million investment losses in 2018 on dedicated assets in support of our executive retirement and deferred compensation plans; and
▪$54 million higher net gains from interest rate and foreign exchange instruments and foreign currency transactions primarily due to:
◦$37
million higher gains in 2019 on foreign currency derivatives as a result of fluctuation of the Mexican peso, and
◦$30 million foreign currency gains in 2019 compared to $3 million foreign currency losses in 2018 on a Mexican peso-denominated loan to IMG JV, which is offset in Equity Earnings, offset by
◦$15 million losses in 2019 on foreign currency derivatives used to hedge exposure to fluctuations in the Peruvian sol related to the sale of our operations in Peru; offset by
▪$97 million higher non-service component of net periodic benefit cost in 2019, including $14 million at SDG&E and $62 million at SoCalGas.
We provide further details of the components
of other (expense) income, net, in Note 1 of the Notes to Consolidated Financial Statements.
Income Taxes
The table below shows the income tax expense (benefit) and ETRs for Sempra Energy Consolidated, SDG&E and SoCalGas.
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
Income tax expense (benefit) from continuing operations
$
249
$
315
$
(49)
Income
from continuing operations before income taxes and equity earnings
$
1,489
$
1,734
$
714
Equity earnings (losses), before income tax(1)
294
30
(236)
Pretax income
$
1,783
$
1,764
$
478
Effective
income tax rate
14
%
18
%
(10)
%
SDG&E:
Income tax expense
$
190
$
171
$
173
Income
before income taxes
$
1,014
$
945
$
849
Effective income tax rate
19
%
18
%
20
%
SoCalGas:
Income
tax expense
$
96
$
120
$
92
Income before income taxes
$
601
$
762
$
493
Effective income tax rate
16
%
16
%
19
%
(1)We
discuss how we recognize equity earnings in Note 6 of the Notes to Consolidated Financial Statements.
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Sempra Energy Consolidated
Sempra Energy’s income tax expense decreased in 2020 compared to 2019 primarily due to a lower ETR. The change in ETR was primarily due to:
▪$44 million income tax benefit in 2020 compared to $71 million income tax expense in 2019 from foreign currency and inflation effects primarily as a result of fluctuation of the Mexican peso;
▪$26
million income tax benefit in 2020 compared to $7 million income tax expense in 2019 from changes to a valuation allowance against certain tax credit carryforwards; and
▪$19 million income tax benefit in 2020 compared to $4 million income tax expense in 2019 related to share-based compensation; offset by
▪$69 million total income tax benefits in 2019 from the release of regulatory liabilities at SDG&E and SoCalGas established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision; and
▪$10 million income tax benefit in 2019 from a reduction in a valuation allowance against certain NOL carryforwards as a result of our decision
to sell our South American businesses.
Sempra Energy’s income tax expense in 2019 compared to an income tax benefit in 2018 was due to higher pretax income and a higher ETR. Pretax income in 2018 was impacted by the impairments at our Sempra LNG and Sempra Renewables segments offset by the gain from sale of assets at Sempra Renewables. The change in ETR was primarily due to:
▪$131 million income tax benefit in 2018 resulting from the reduced outside basis difference in Sempra LNG as a result of the impairment of certain non-utility natural gas storage assets; and
▪$45 million higher income tax expense in 2019 from foreign currency and inflation effects primarily as a result of fluctuation of the Mexican peso; offset by
▪$69
million total income tax benefits in 2019 from the release of regulatory liabilities at SDG&E and SoCalGas established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision;
▪$41 million income tax expense in 2018 to adjust provisional estimates recorded in 2017 for the effects of tax reform;
▪$21 million income tax expense in 2018 associated with Aliso Canyon natural gas storage facility litigation; and
▪$10 million income tax benefit in 2019 from a reduction in a valuation allowance against certain NOL carryforwards as a result of our decision to sell our South American businesses.
We report as part
of our pretax results the income or loss attributable to NCI. However, we do not record income taxes for a portion of this income or loss, as some of our entities with NCI are currently treated as partnerships for income tax purposes, and thus we are only liable for income taxes on the portion of the earnings that are allocated to us. Our pretax income, however, includes 100% of these entities. If our entities with NCI grow, and if we continue to invest in such entities, the impact on our ETR may become more significant.
We discuss the impact of foreign currency exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Notes 1 and 8 of the Notes to Consolidated Financial Statements for further details about our accounting for income taxes and items subject to flow-through treatment.
SDG&E
SDG&E’s
income tax expense increased in 2020 compared to 2019 primarily due to:
▪higher pretax income; and
▪$31 million income tax benefit in 2019 from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision; offset by
▪higher income tax benefits in 2020 from flow-through deductions.
SDG&E’s income tax expense decreased in 2019 compared to 2018 due to a lower ETR offset by higher pretax income. The change in ETR was primarily due to a $31 million income tax benefit in 2019 from the release of a regulatory liability established in connection
with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision.
SoCalGas
SoCalGas’ income tax expense decreased in 2020 compared to 2019 primarily due to:
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▪lower pretax income; and
▪higher income tax benefits in 2020 from flow-through deductions; offset by
▪$38 million income tax benefit in 2019 from the release of a regulatory liability established in connection with 2017 tax reform for excess
deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision.
SoCalGas’ income tax expense increased in 2019 compared to 2018 due to higher pretax income offset by a lower ETR. The change in ETR was primarily due to:
▪$38 million income tax benefit in 2019 from the release of a regulatory liability established in connection with 2017 tax reform for excess deferred income tax balances that the CPUC directed be allocated to shareholders in a January 2019 decision; and
▪$21 million income tax expense in 2018 associated with the Aliso Canyon natural gas storage facility litigation.
Equity
Earnings
Equity earnings increased by $435 million to $1.0 billion in 2020 compared to 2019 primarily due to:
▪$367 million higher equity earnings from Cameron LNG JV primarily due to commencement of Phase 1 commercial operations;
▪$94 million higher equity earnings at IMG JV, primarily due to higher revenues from the start of commercial operations of the Sur de Texas-Tuxpan marine pipeline and foreign currency effects, including $42 million foreign currency gains in 2020 compared to $30 million foreign currency losses in 2019 on IMG JV’s Mexican peso-denominated loans from its JV owners, which is fully offset in Other (Expense) Income, Net, offset by lower AFUDC equity;
▪$51 million higher equity earnings
at Oncor Holdings primarily due to higher revenues from rate updates and customer growth, the acquisition of InfraREIT in May 2019 and higher AFUDC equity, offset by unfavorable weather and increased operating costs; and
▪$23 million higher equity earnings at TAG JV primarily due to lower income tax expense in 2020; offset by
▪$100 million equity losses at RBS Sempra Commodities in 2020, which represents an estimate of our obligations to settle pending tax matters and related legal costs at our equity method investment.
Equity earnings increased by $405 million to $580 million in 2019 compared to 2018 primarily due to:
▪$174 million increase at Sempra Renewables, including $200
million other-than-temporary impairment of certain wind equity method investments in 2018;
▪$155 million higher equity earnings, net of income tax, from our investment in Oncor Holdings, which we acquired in March 2018;
▪$65 million impairment of our RBS Sempra Commodities equity method investment in 2018; and
▪$24 million higher equity earnings from Cameron LNG JV including:
◦$50 million increase primarily due to Train 1 commencing commercial operation under its tolling agreements in August 2019, offset by
◦$26 million decrease due to the write-off of unamortized debt issuance
costs and associated fees related to the JV’s debt refinancing; offset by
▪$20 million lower equity earnings, net of income tax, from IMG JV, including $30 million foreign currency losses in 2019 compared to $3 million foreign currency gains in 2018 on its Mexican peso-denominated loans from its JV owners, which is fully offset in Other Income, Net.
Earnings Attributable to Noncontrolling Interests
Earnings attributable to NCI were $172 million for 2020 compared to $164 million for 2019. The net change of $8 million (5%) was primarily due to an increase in earnings attributable to NCI at Sempra Mexico mainly from foreign currency effects as a result of fluctuation of the Mexico peso, offset by a decrease due to the sales of our Peruvian businesses in April 2020 and Chilean businesses
in June 2020.
Earnings attributable to NCI were $164 million for 2019 compared to $76 million for 2018. The net change of $88 million included:
▪$1 million earnings attributable to NCI at Sempra Renewables in 2019 compared to $58 million losses in 2018 primarily due to the sales of our tax equity investments in December 2018 and April 2019; and
▪$36 million losses attributable to NCI at Sempra LNG in 2018 due to the net impairment of certain non-utility natural gas storage assets.
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Preferred Dividends
Preferred dividends increased
by $26 million (18%) to $168 million in 2020 compared to 2019 primarily due to dividends associated with our series C preferred stock, which was issued in June 2020.
Preferred dividends increased by $17 million (14%) to $142 million in 2019 compared to 2018 primarily due to dividends associated with our series B preferred stock, which was issued in July 2018.
IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS
Because our natural gas distribution utility in Mexico, Ecogas, uses its local currency as its functional currency, revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra Energy Consolidated’s
results of operations. Prior to the sales of our South American businesses in 2020, our operations in South America used their local currency as their functional currency.
Foreign Currency Translation
Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra Energy’s comparative results of operations. Changes in foreign currency translation rates between years resulted in $9 million lower earnings in 2020 compared to 2019 and $8 million lower earnings in 2019 compared to 2018.
Transactional Impacts
Income statement activities at our foreign operations and their JVs are also impacted by transactional gains and losses, a summary of which is shown in the table below:
TRANSACTIONAL
(LOSSES) GAINS FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
Total reported amounts
Transactional (losses) gains included in reported amounts
Income from continuing operations, net of income tax
2,255
1,999
938
8
(70)
(41)
Income
from discontinued operations, net of income tax
1,850
363
188
15
2
6
Earnings attributable to common shares
3,764
2,055
924
(1)
(39)
(21)
Foreign
Currency Exchange Rate and Inflation Impacts on Income Taxes and Related Hedging Activity
Our Mexican subsidiaries have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that are affected by Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities, which are significant, denominated in the Mexican peso that must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation may expose us to fluctuations in Income Tax Expense, Other (Expense) Income, Net and Equity Earnings. We may use foreign
currency derivatives as a means to help manage exposure to the currency exchange rate on our monetary assets and liabilities, and this derivative activity impacts Other (Expense) Income, Net. However, we generally do not hedge our deferred income tax assets and liabilities, which makes us susceptible to volatility in income tax expense caused by exchange rate fluctuations and inflation.
We also utilized foreign currency derivatives to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sales of our operations in Peru and Chile in discontinued operations.
Other Transactions
Although the financial statements of most of our Mexican subsidiaries and JVs have the U.S. dollar as the functional currency, some transactions may be denominated in the local currency; such transactions are remeasured into U.S. dollars.
This
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remeasurement creates transactional gains and losses that are included in Other (Expense) Income, Net, for our consolidated subsidiaries and in Equity Earnings for our JVs.
We utilize cross-currency swaps that exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. The impacts of these cross-currency swaps are offset in OCI and are reclassified from AOCI into earnings through Other (Expense) Income, Net and Interest Expense as settlements occur.
Certain of our Mexican pipelines (namely Los Ramones I at IEnova Pipelines and Los Ramones Norte at TAG JV) generate revenue
based on tariffs that are set by government agencies in Mexico, with contracts denominated in Mexican pesos that are indexed to the U.S. dollar, adjusted annually for inflation and fluctuation in the exchange rate. The resultant gains and losses from remeasuring the local currency amounts into U.S. dollars and the settlement of foreign currency forwards and swaps related to these contracts are included in Revenues: Energy-Related Businesses or Equity Earnings.
CAPITAL
RESOURCES AND LIQUIDITY
OVERVIEW
Sempra Energy Consolidated
Impact of the COVID-19 Pandemic
On March 11, 2020, the World Health Organization declared the COVID-19 outbreak to be a pandemic. The U.S. government officially declared a national emergency on March 13, 2020, and the Mexican government announced a national state of sanitary emergency on March 30, 2020. The COVID-19 pandemic is materially impacting the economy, including a surge in unemployment claims and, at times, substantial volatility in financial markets, and has
resulted in action by governments and other authorities to help address these effects. For example:
▪The CPUC required that all energy companies under its jurisdiction, including the California Utilities, take action to implement several emergency customer protection measures to support California customers. The measures currently apply to all residential and small business customers affected by the COVID-19 pandemic and include suspending service disconnections due to nonpayment, waiving late payment fees, and offering flexible payment plans to all customers experiencing difficulty paying their electric or gas bills. The CPUC approved a resolution authorizing each of the California Utilities to track and request recovery of incremental costs associated with complying with residential and small business customer protection measures implemented by the CPUC related to the COVID-19 pandemic, including
costs associated with suspending service disconnections and uncollectible expenses that arise from these customers’ failure to pay. Although we are tracking these costs in various regulatory mechanisms, recovery is not assured. The continuation of these circumstances could result in a further reduction in payments received from the California Utilities’ customers and a further increase in uncollectible accounts, which could become material, and any inability or delay in recovering all or a substantial portion of these costs could have a material adverse effect on the cash flows, financial condition and results of operations of Sempra Energy, SDG&E and SoCalGas. We discuss regulatory mechanisms in Note 4 of the Notes to Consolidated Financial Statements.
▪In Texas, the PUCT issued orders creating the COVID-19 Electricity Relief Program and suspending service disconnections due to nonpayment
for customers enrolled in the program through September 30, 2020. The COVID-19 Electricity Relief Program created a fund through which transmission and distribution utilities and retail electric providers in Texas may seek to recover certain costs (including transmission and distribution utility electricity delivery charges) of providing uninterrupted services to customers facing financial hardship due to the effects of the COVID-19 pandemic. Financial assistance under the program was available to enrolled residential customers for electricity bills issued on or after March 26, 2020 through September 30, 2020. The PUCT has also authorized the use of a regulatory asset accounting mechanism and a subsequent process through which regulated utility companies may seek future recovery of other expenses resulting from the effects
of the COVID-19 pandemic. Rate regulation is premised on the full recovery of prudently incurred costs. The regulatory assets established with respect to COVID-19 pandemic costs are subject to PUCT review for reasonableness and possible disallowance. Any inability to recover these costs could have an adverse effect on the cash flows, financial condition and results of operations of Sempra Energy.
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▪On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted and signed into law in response to the COVID-19 pandemic. Among other things, the CARES Act contains significant business tax provisions, including a delay of payment of employer payroll taxes
and an acceleration of refunds of corporate alternative minimum tax (AMT) credits. Sempra Energy, SDG&E and SoCalGas have deferred payment of the employer’s share of payroll taxes through the end of 2020, with half of such taxes to be paid by the end of 2021 and the other half to be paid by the end of 2022. In 2020, Sempra Energy filed and received a refund claim for its corporate AMT credits, rather than receiving it in installments through 2021.
Our businesses that invest in, develop and operate energy infrastructure and provide electric and gas services to customers have been identified as critical or essential services in the U.S. and Mexico and have continued to operate throughout the COVID-19 pandemic. As our businesses continue to operate, our priority is the safety of our employees, customers, partners and the communities we serve. We and other companies, including our partners, are taking steps to try to protect
the health and well-being of our employees and other stakeholders. For example, we have activated our business continuity plans and continue to work closely with local, state and federal authorities to provide essential services with minimum interruption to customers and in accordance with applicable shelter-in-place and other orders. We have implemented precautionary measures across our businesses, including requiring employees to work remotely when possible, restricting non-essential business travel, increasing facility sanitization and communicating proper health and safety protocols to employees. We also have engaged an infectious disease expert to advise us during this public health crisis. Throughout 2020, these actions have not required significant outlays of capital and have not had a material impact on our results of operations, but these or other measures that we may implement in the future could have a material adverse effect on our liquidity, cash flows,
financial position and results of operations if circumstances related to the COVID-19 pandemic worsen or continue for an extended period of time.
The COVID-19 pandemic and its widespread effects also have impacted our capital plans, liquidity and asset values, as we discuss with respect to each of our segments below. We perform recovery testing of our recorded asset values when market conditions indicate that such values may not be recoverable. Given the current environment (including the decline in the price of our common stock, financial market volatility, high unemployment rates, reduction in customer collections that could become material, inability to secure permits and other authorizations due to government closures, and governments pursuing new laws or policies that modify pre-existing contract terms or alter operations), we evaluated whether these events or changes in circumstances resulted in an impairment of our long-lived
assets, intangible assets or goodwill in 2020 and concluded that no such impairment was warranted. However, as the effects of the COVID-19 pandemic evolve, we will continue to periodically assess the need to perform interim impairment tests. A significant impairment charge related to our long-lived assets, intangible assets or goodwill would have a material adverse effect on our results of operations in the period in which it is recorded.
For a further discussion of risks and uncertainties related to the COVID-19 pandemic, see below in “Part I – Item 1A. Risk Factors.”
Liquidity
We expect to meet our cash requirements through cash flows from operations, unrestricted cash and cash equivalents, proceeds from recent asset sales, borrowings under our credit facilities, distributions from our equity method investments, issuances of debt,
project financing and partnering in JVs. We believe that these cash flow sources, combined with available funds, will be adequate to fund our current operations, including to:
▪finance capital expenditures
▪meet liquidity requirements
▪fund dividends
▪fund new business or asset acquisitions or start-ups
▪fund capital contribution requirements
▪repay long-term debt
▪fund expenditures related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas
storage facility
Sempra Energy and the California Utilities currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow money at reasonable rates from commercial banks, under existing revolving credit facilities or through public offerings registered with the SEC. However, the money markets and capital markets in general, including particularly the commercial paper markets, and the availability of financing from commercial banks have experienced distress at times during 2020 due to the COVID-19 pandemic, and our ability to access the money markets and capital markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if changing economic conditions and disruptions to the money markets and capital markets, due to the COVID-19 pandemic or otherwise, worsen. In addition, our financing
activities and actions by credit rating agencies, as well as many other factors, could
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negatively affect the availability and cost of both short-term and long-term financing. Also, cash flows from operations may be impacted by the timing of commencement and completion, and potentially cost overruns, of large projects. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) and investments in new businesses. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain our investment-grade credit ratings and capital
structure.
We have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits and nuclear decommissioning. Changes in asset values, which are dependent on activity in the equity and fixed income markets, have not materially and adversely affected the trust funds’ abilities to make required payments. However, changes in these or other factors in future periods, such as changes to discount rates, assumed rates of return, mortality tables and regulations, may impact funding requirements for pension and other postretirement benefits plans. Funding requirements for SDG&E’s NDT could also be impacted by the timing and amount of SONGS decommissioning costs. At the California Utilities, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and SDG&E’s NDT, including our investment allocation strategies for assets in these
trusts, in Notes 9 and 15, respectively, of the Notes to Consolidated Financial Statements.
Available Funds
Our committed lines of credit provide liquidity and support commercial paper. As we discuss in Note 7 of the Notes to Consolidated Financial Statements, Sempra Energy, Sempra Global, SDG&E and SoCalGas each have five-year credit agreements expiring in 2024. In addition, Sempra Mexico has committed lines of credit that expire in 2021 and 2024 and an uncommitted revolving credit facility that expires in 2023. The table below shows the amount of available funds at December 31, 2020, including available unused credit on these primary U.S. and foreign lines of credit.
(1) Amounts at Sempra Energy Consolidated include $295 million held in non-U.S. jurisdictions. We discuss repatriation in Note 8 of the Notes to Consolidated Financial Statements.
(2) Available unused credit is the total available on Sempra Energy’s, Sempra Global’s, SDG&E’s, SoCalGas’ and Sempra Mexico’s credit facilities that we discuss in Note 7 of the Notes to Consolidated Financial Statements.
(3) Because
our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.
Short-Term Borrowings
We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures, acquisitions or start-ups. Our California Utilities use short-term debt primarily to meet working capital needs. Due to volatility in commercial paper markets shortly following the start of the COVID-19 pandemic, commercial paper borrowing at that time became less desirable and, in some cases, not competitive or unavailable. To secure sufficient sources of liquidity during this period, Sempra Energy, Sempra Global, SDG&E, SoCalGas and IEnova each drew amounts under their respective credit facilities and Sempra Energy and SDG&E each also obtained short-term
term loans, much of which has been subsequently repaid. Revolving lines of credit, term loans and commercial paper were our primary sources of short-term debt funding in 2020.
We discuss our short-term debt activities in Note 7 of the Notes to Consolidated Financial Statements.
The following table shows selected statistics for our commercial paper borrowings.
Major issuances of and payments on long-term debt in 2020 included the following:
LONG-TERM DEBT ISSUANCES AND PAYMENTS
(Dollars in millions)
Issuances:
Amount at issuance
Maturity
SDG&E
variable rate 364-day term loan
$
200
2021
SDG&E variable rate revolving line of credit
200
2024
SDG&E 1.70% first mortgage bonds
800
2030
SDG&E 3.32% first mortgage bonds
400
2050
SoCalGas
senior unsecured variable rate notes
300
2023
SoCalGas 2.55% first mortgage bonds
650
2030
Sempra Mexico 2.38% bank loans
100
2034
Sempra Mexico 2.90% bank loans
241
2034
Sempra
Mexico 4.75% senior unsecured notes
800
2051
Sempra LNG variable rate notes
17
2025
Payments:
Payments
Maturity
Sempra
Energy 2.4% notes
$
500
2020
Sempra Energy 2.4% notes
500
2020
Sempra Energy 2.85% notes
400
2020
Sempra Energy variable rate notes
700
2021
SDG&E
1.914% amortizing first mortgage bonds
36
2020
SDG&E variable rate revolving line of credit
200
2024
SDG&E 5.875% first mortgage bonds
176
2034
SDG&E 4% first mortgage bonds
75
2039
Sempra
Mexico amortizing variable rate notes
41
2020
Sempra Mexico amortizing fixed and variable rate bank loans
25
2020
SDG&E used the proceeds from its long-term debt offerings to repay first mortgage bonds, commercial paper and line of credit borrowings, for working capital and for other general corporate purposes.
SoCalGas used the proceeds from its long-term debt offerings to repay commercial paper and for general corporate purposes.
Sempra
Mexico used the proceeds from its issuances of long-term debt to finance the construction of solar generation projects, to repay line of credit borrowings and for other general corporate purposes.
We discuss our long-term debt activities in Note 7 of the Notes to Consolidated Financial Statements.
Credit Ratings
The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels in 2020. On January 29, 2021, Moody’s placed the long-term debt ratings of SDG&E on review for upgrade.
A
downgrade of Sempra Energy’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in a requirement for collateral to be posted in the case of certain financing arrangements and may materially and adversely affect the market prices of their equity and debt securities, the rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. We provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors.”
Sempra Energy has agreed that, if the credit rating of Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A+ and A at
Moody’s, S&P and Fitch, respectively, at December 31, 2020.
Sempra Energy, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit that may be impacted by each borrower’s credit rating. Depending on the severity of the downgrade:
▪If Sempra Energy were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 to 50 bps. The commitment fee on available unused credit would also increase 5 to 10 bps.
▪If
SDG&E were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 to 50 bps. The commitment fee on available unused credit would also increase 5 to 10 bps.
▪If SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 2.5 bps.
Sempra Energy’s and SDG&E’s credit ratings also may affect their respective credit limits related to derivative instruments, as we discuss in Note 11 of the Notes to Consolidated Financial Statements.
Loans to/from Affiliates
At December 31, 2020, Sempra Energy had $780
million in loans due from unconsolidated affiliates and $275 million in loans due to unconsolidated affiliates.
California Utilities
SDG&E’s and SoCalGas’ operations have historically provided relatively stable earnings and liquidity. Their future performance and liquidity will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature, litigation and the changing energy marketplace, as well as other matters described in this report.
SDG&E and SoCalGas expect that the available unused credit from their credit facilities described above, cash flows from operations, and debt issuances will continue to be adequate to fund their
respective current operations and planned capital expenditures. The California Utilities are continuing to monitor the impacts of the COVID-19 pandemic on cash flows and results of operations. Some customers are experiencing a diminished ability to pay their electric or gas bills, leading to slower payments and higher levels of nonpayment than has been the case historically. These impacts could become significant and could require modifications to our financing plans. The California Utilities manage their capital structure and pay dividends when appropriate and as approved by their respective boards of directors.
As we discuss in Note 4 of the Notes to Consolidated Financial Statements, changes in balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over- and undercollected status, may have a significant impact on cash flows. These changes generally represent the difference between
when costs are incurred and when they are ultimately recovered in rates through billings to customers.
Disconnection OIR
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In June 2020, the CPUC issued a decision addressing service disconnections that, among other things, allows each of the California Utilities to establish a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills. This decision also directs the California Utilities to establish an AMP that provides successfully participating, income-qualified residential customers with relief from outstanding utility bill amounts and is effective as of February 2021. The California Utilities have recorded increases in their
allowances for uncollectible accounts at December 31, 2020 primarily related to expected forgiveness of outstanding bill amounts for customers eligible under the AMP. The AMP could result in a further reduction in payments received from the California Utilities’ customers and a further increase to uncollectible accounts, which could become material, and any inability to recover these costs could have a material adverse effect on the cash flows, financial condition and results of operations of Sempra Energy, SDG&E and SoCalGas.
Pipeline Safety Enhancement Plan
In November 2018, SoCalGas and SDG&E filed a joint application with the CPUC for a reasonableness review of PSEP project costs totaling $941 million for 83 pipeline safety enhancement projects. SoCalGas and SDG&E subsequently entered into a settlement agreement for
cost recovery of $935 million ($806 million for SoCalGas and $129 million for SDG&E). A final decision was approved in August 2020, granting the proposed settlement agreement as well as the amortization schedule for recovery of costs. The final decision was implemented in rates on October 1, 2020.
CCM
A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized return on rate base and addresses the CCM. The CCM, if triggered in 2021, would be effective January 1, 2022, and would automatically update the California Utilities’ authorized cost of debt based on actual costs and update the California Utilities’ authorized ROE. A trigger of the CCM that requires a downward adjustment beginning January
1, 2022 could materially adversely affect the results of operations and cash flows of Sempra Energy and, depending on the CCM that is triggered, SDG&E and SoCalGas. We discuss the CCM further in “Part I – Item 1. Business – Ratemaking Mechanisms – California Utilities – Cost of Capital Proceedings,”“Part I – Item 1A. Risk Factors” and in Note 4 of the Notes to Consolidated Financial Statements.
SDG&E
Wildfire Fund
In 2019, SDG&E recorded a Wildfire Fund asset for committed shareholder contributions to the Wildfire Fund. We describe the Wildfire Legislation and related accounting treatment in Note 1 of the Notes to Consolidated Financial Statements.
SDG&E
is exposed to the risk that the participating California electric IOUs may incur third-party wildfire claims for which they will seek recovery from the Wildfire Fund. In such a situation, 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 any of the participating IOUs. As a result, if any California electric IOU’s equipment is determined to be a cause of a fire, it could have a material adverse effect on SDG&E’s and Sempra Energy’s financial condition and results of operations up to the carrying value of our Wildfire Fund asset, with additional potential material exposure if SDG&E’s equipment is determined to be a cause of a fire. In addition, the Wildfire Fund could be completely exhausted due to fires in the other California electric IOUs’ service territories, by fires in SDG&E’s service territory or by a combination
thereof. In 2020, California experienced some of the largest wildfires in its history (measured by acres burned), including fires in SDG&E’s service territory. Although SDG&E is not aware of any claims made against the Wildfire Fund by any participating IOU, there is no assurance that the equipment of a California electric IOU will not be determined to be a cause of one or more of these fires. In the event that the Wildfire Fund is materially diminished, exhausted or terminated, SDG&E will lose the protection afforded by the Wildfire Fund, and as a consequence, a fire in SDG&E’s service territory could cause a material adverse effect on SDG&E’s and Sempra Energy’s cash flows, results of operations and financial condition.
SoCalGas
SoCalGas’
future performance and liquidity will be impacted by the resolution of legal, regulatory and other matters concerning the Leak, which we discuss below, in Note 16 of the Notes to Consolidated Financial Statements, and in “Part I – Item 1A. Risk Factors.”
Aliso Canyon Natural Gas Storage Facility Gas Leak
From October 23, 2015 through February 11, 2016, SoCalGas experienced a natural gas leak from one of the injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility located in Los Angeles County. In February 2016, CalGEM confirmed that the well was permanently sealed.
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Cost
Estimates, Accounting Impact and Insurance.At December 31, 2020, SoCalGas estimates certain costs related to the Leak are $1,627 million (the cost estimate). This cost estimate may increase significantly as more information becomes available. A substantial portion of the cost estimate has been paid, and $451 million is accrued as Reserve for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets.
Except for the amounts paid or estimated to settle certain actions, the cost estimate does not include litigation or regulatory costs to the extent it is not possible to predict at this time 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. 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. These costs not included in the cost estimate could be significant and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
We have received insurance payments for many of the costs included in the cost estimate, including temporary relocation and associated processing costs, control-of-well expenses, costs of the government-ordered response to the Leak, certain legal costs and lost gas. As of December 31, 2020, we recorded the expected recovery of the cost estimate related to the Leak of $445 million as Insurance
Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets. This amount is exclusive of insurance retentions and $834 million of insurance proceeds we received through December 31, 2020. We intend to pursue the full extent of our insurance coverage for the costs we have incurred. Other than insurance for certain future defense costs we may incur as well as directors’ and officers’ liability, we have exhausted all of our insurance in this matter. We continue to pursue other sources of insurance coverage for costs related to this matter, but we may not be successful in obtaining additional insurance recovery for any of these costs. If we are not able to secure additional insurance recovery, if any costs we have recorded as an insurance receivable are not collected, if there are delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes while the
associated costs are not tax deductible, such amounts, which could be significant, could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Natural Gas Storage Operations and Reliability.Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and consumer heating needs in the winter. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important 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 injection operations in July
2017 based on limited operating ranges for the field. In February 2017, the CPUC opened a proceeding pursuant to SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including considering alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated.
The CPUC has issued a series of directives to SoCalGas specifying the range of working gas to be maintained in the Aliso Canyon natural gas storage facility as well as protocols for the withdrawal of gas, to support safe and reliable natural gas service. Withdrawals of natural gas from the facility were made in 2018, 2019 and 2020 to augment natural gas supplies to meet consumer demand, including for electric generation needs.
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, 2020, the Aliso Canyon natural gas storage facility had a net book value of $821 million. Any significant impairment of this asset, or higher operating costs and additional capital expenditures incurred by SoCalGas that 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.
OSCs – Energy Efficiency and Advocacy
As we discuss in Note 4 of
the Notes to Consolidated Financial Statements, in October 2019, the CPUC issued an OSC to determine whether SoCalGas should be sanctioned for violation of certain CPUC code sections and orders related to energy efficiency codes and standards advocacy activities undertaken by SoCalGas in 2018. In December 2019, the CPUC issued a second OSC to determine whether SoCalGas is entitled to the energy efficiency program’s shareholder incentives for codes and standards advocacy in 2016 and 2017, whether its shareholders should bear the costs of those advocacy activities, and to address whether any other remedies are appropriate. The scope of this second OSC was later expanded to include energy efficiency program years 2014 and 2015, and SoCalGas’ engagement with local governments on proposed reach codes. If the CPUC were to assess fines or penalties on SoCalGas associated with these OSCs, they could have a material adverse effect on SoCalGas’ and
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Sempra
Energy’s results of operations, financial condition and cash flows. We expect CPUC decisions on these OSCs in the first half of 2021.
Sempra Texas Utilities
Oncor 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 from operations and with proceeds from indebtedness. In the event that Oncor fails to meet its capital requirements or is unable to access sufficient capital to finance its ongoing needs, we may elect to make additional capital contributions to Oncor (as our commitments to the PUCT prohibit us from making loans to Oncor) which could be substantial and 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, liquidity, financial condition and prospects.
Oncor’s ability to pay dividends may be limited by factors such as its credit ratings, regulatory capital requirements, debt-to-equity ratio approved by the PUCT and other restrictions. In addition, Oncor will not pay dividends if a majority of Oncor’s independent directors or any minority member director determines it is in the best interests of Oncor to retain such amounts to meet expected future requirements.
Sempra Mexico
Construction Projects and Related Regulatory Matters
Sempra Mexico is currently constructing additional terminals for the receipt,
storage, and delivery of liquid fuels in the vicinity of Mexico City, Puebla, Veracruz and Topolobampo. Sempra Mexico is also constructing a new solar facility (Border Solar) in Juárez, Chihuahua, through which it intends to supply renewable energy to several private companies. Sempra Mexico is currently developing additional terminals for the receipt, storage, and delivery of liquid fuels in the vicinity of Manzanillo, Guadalajara and Ensenada. We expect to fund these capital expenditures, investments and operations at IEnova with available funds, including credit facilities, and funds internally generated by the Sempra Mexico businesses, as well as funds from project financing, sales of securities, interim funding from the parent or affiliates, and partnering in JVs. We expect the projects under construction to commence commercial operations on various dates in 2021. However, expected commencement dates could be delayed by worsening or extended disruptions of project
construction or development caused by the COVID-19 pandemic or other factors outside our control. Sempra Mexico is continuing to monitor the impacts of the COVID-19 pandemic on cash flows and results of operations. See “Part I – Item 1A. Risk Factors.”
As we discuss in Note 16 of the Notes to Consolidated Financial Statements, in the second quarter of 2020, certain Mexican governmental agencies issued orders and regulations that would reduce or limit the renewable energy sector’s participation in the country’s energy market. Those orders would, among other things, create barriers for renewable energy facilities to enter the wholesale electricity market, prevent renewable energy projects currently in construction from reaching operations and increase grid fees for legacy renewables and cogeneration energy contract holders. IEnova and other companies affected by such measures, certain non-governmental environmental organizations
or advocacy groups, and COFECE, Mexico’s antitrust regulator, have filed legal complaints with the respective Mexican courts to prevent such measures from going into effect. In most cases, the courts have sided with the complainants and such measures have been stayed temporarily. The court-ordered injunctions provide relief until Mexico’s Federal District Court ultimately resolves the amparo claims (constitutional protection lawsuits).
An unfavorable final decision on these amparo challenges, or the potential for an extended dispute, could impact our ability to successfully complete construction of our Border Solar project, which is not yet commercially operating, or to complete such construction in a timely manner and within expected budgets, may impact our ability to operate our wind and solar facilities already in service at existing levels or at all, and may adversely affect our ability to develop new projects, any of
which may have a material adverse impact on our results of operations and cash flows and our ability to recover the carrying values of our renewable energy investments in Mexico.
The ability to successfully complete major construction projects is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I – Item 1A. Risk Factors.”
Other Legal and Regulatory Matters
As we discuss in Note 16 of the Notes to Consolidated Financial Statements, IEnova received force majeure payments for the Guaymas-El Oro segment of the Sonora pipeline from August 2017 to August 2019. Under an agreement between IEnova and the CFE, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is repaired. If the pipeline is not repaired by March
14, 2021 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 (which have not commenced) and resume operations in the Guaymas-El Oro segment of
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the Sonora pipeline 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. At December 31, 2020, the Guaymas-El Oro segment of the Sonora pipeline had a net book value of $447 million. The Sasabe-Puerto Libertad-Guaymas segment
of the Sonora pipeline remains in full operation and is not impacted by these developments.
In May 2020, the two third-party capacity customers at the ECA Regas Facility, Shell Mexico and Gazprom, asserted that a 2019 update of the general terms and conditions for service at the facility, as approved by the CRE, resulted in a breach of contract by IEnova and a force majeure event. Citing these circumstances, the customers subsequently stopped making payments of amounts due under their respective LNG storage and regasification agreements. IEnova has rejected the customers’ assertions and has drawn (and expects to continue to draw) on the customers’ letters of credit provided as payment security. The parties engaged in discussions under the applicable contractual dispute resolution procedures without coming to a mutually acceptable resolution. In July 2020, Shell Mexico submitted a request for arbitration of the dispute and although
Gazprom has joined the proceeding, Gazprom has replenished the amounts drawn on its letter of credit and has resumed making regular monthly payments under its LNG storage and regasification agreement. IEnova intends to avail itself of its available claims, defenses, rights and remedies in the arbitration proceeding, including seeking dismissal of the customers’ claims. In addition to the arbitration proceeding, Shell Mexico also filed a constitutional challenge to the CRE’s approval of the update to the general terms and conditions. In October 2020, Shell Mexico’s request to stay CRE’s approval was denied and, subsequently, Shell Mexico filed an appeal of that decision.
Potential Acquisition of ESJ
As we discuss in Note 5 of the Notes to Consolidated Financial Statements, in February 2021, IEnova agreed to acquire Saavi Energía’s 50% interest in ESJ for approximately $83 million.
At December 31, 2020, IEnova owned a 50% interest in ESJ, which is accounted for as an equity method investment. Upon completion of the acquisition, IEnova will own 100% of ESJ and will consolidate it. We expect to complete the acquisition in the first half of 2021, subject to various closing conditions, including authorizations from the FERC and COFECE.
ESJ is constructing a second wind power generation facility, which we expect will be completed in late 2021 or in the first quarter of 2022 and will have a nameplate capacity of 108 MW.
Exchange Offer
On December 2, 2020, we announced a non-binding offer to acquire up to 100% of the publicly held shares of IEnova in exchange for shares of our common stock at an exchange ratio of 0.0313 shares
of our common stock for each one IEnova ordinary share, which exchange ratio remains subject to approval by the Sempra Energy board of directors. We expect to complete this transaction in the second quarter of 2021, subject to authorization by the SEC, CNBV and Mexican Stock Exchange and other closing conditions. This proposed transaction is subject to a number of risks that we discuss in “Part I – Item 1A. Risk Factors.”
IEnova Common Stock Repurchase Fund
In April 2020, IEnova’s shareholders approved an increase to a previously approved fund for IEnova to repurchase shares of its common stock for a maximum amount of $500 million, increased from $250 million. As of February 25, 2021, IEnova has repurchased 81,742,780 shares of its outstanding common stock held by NCI for approximately $248 million since the inception of the
fund in 2018, increasing Sempra Energy’s ownership interest in IEnova from 66.6% to 70.2% over this period. IEnova does not intend to repurchase shares of its common stock during the pendency of the exchange offer described above. Following the completion of the exchange offer, IEnova may repurchase shares under the existing program from time-to-time at the discretion of management.
Sempra LNG
Sempra LNG is pursuing development of additional LNG export facilities on the Gulf Coast and Pacific Coast of North America through its proposed Cameron LNG JV Phase 2 liquefaction expansion project in Louisiana, ECA LNG liquefaction export projects in Mexico, and Port Arthur LNG liquefaction export project in Texas. We expect Sempra LNG to require funding for the development
and expansion of its portfolio of projects, which may be financed through a combination of operating cash flows, funding from the parent, project financing and participating in JVs.
Sempra LNG, through its 50.2% interest in Cameron LNG JV, operates a three-train natural gas liquefaction facility with an export capacity of 12 Mtpa of LNG, which we refer to as Phase 1. The majority of the construction was project-financed at the JV, with most or all of the remainder of the capital requirements provided by the project partners, including Sempra Energy,
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through equity contributions under the project equity agreements.
Cameron LNG JV achieved commercial operations of Train 1, Train 2 and Train 3 under its tolling agreements in August 2019, February 2020 and August 2020, respectively.
As we discuss below in “Off-Balance Sheet Arrangements” and in Note 6 of the Notes to Consolidated Financial Statements, Sempra Energy has guaranteed a maximum of $i4.0 billion related to Cameron LNG JV’s project financing and financing-related agreements for the Phase 1 project. These guarantees terminate upon Cameron LNG JV achieving “financial
completion” of the Phase 1 three-train liquefaction export project, including all three trains achieving commercial operation and meeting certain operational performance tests, which are currently underway. Cameron LNG JV’s financing agreements contain events of default customary for such financings, including a failure to achieve financial completion of the project by a deadline of September 30, 2021 (with up to an additional 365 days extension beyond such date permitted in cases of force majeure). Pursuant to the financing agreements, Cameron LNG JV is restricted from making distributions to its project owners, including Sempra LNG, from January 1, 2021 until the earlier of September 30, 2021 and the achievement of financial completion, at which time any deferred distributions will be released. A delay that results
in a failure to achieve financial completion by September 30, 2021 would result in an event of default under Cameron LNG JV’s financing agreements and a potential demand on Sempra Energy’s guarantees. We anticipate that the guarantees will be terminated in the first half of 2021, but this timing could be delayed, perhaps substantially, if the operational performance tests required to achieve financial completion are not completed due to weather-related events, other events or other factors beyond our control. If, due to Cameron LNG JV’s failure to satisfy the financial completion criteria by the applicable deadline, we are required to repay some or all of the $i4.0
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.
For a discussion of our investment in Cameron LNG JV, JV financing, Sempra Energy guarantees, the risks discussed above and other risks relating to the Cameron LNG JV Phase 1 liquefaction export project that could adversely affect our future performance, see “Part I – Item 1A. Risk Factors.”
Cameron LNG JV has received the major permits and FTA and non-FTA approvals necessary to expand the current configuration of the Cameron LNG JV liquefaction project beyond Phase 1. The permits obtained for the Phase 2 project include up to two additional liquefaction trains and up to two additional full containment
LNG storage tanks (one of which was permitted with the Phase 1 three-train project).
Sempra Energy has entered MOUs with TOTAL SE, Mitsui & Co., Ltd. and Mitsubishi Corporation that provide a framework for cooperation for the development of and 100% of the offtake from the potential Cameron LNG JV Phase 2 project. The ultimate participation of and offtake by TOTAL SE, Mitsui & Co., Ltd. and Mitsubishi Corporation remains subject to negotiation and finalization of definitive agreements, among other factors, and TOTAL SE, Mitsui & Co., Ltd. and Mitsubishi Corporation have no commitment to participate in or enter into offtake agreements with the Phase 2 project until such definitive agreements are established.
Expansion of the Cameron LNG JV liquefaction facility beyond the first three trains is subject to certain restrictions and conditions under the JV project financing
agreements, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from the Phase 1 project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the partners, including with respect to the equity investment obligation of each partner. Discussions among all the Cameron LNG JV partners have been taking place regarding how an expansion may be structured and we expect that discussions will continue. There is no assurance that the Cameron LNG JV members will unanimously agree in a timely manner or at all on an expansion structure, which, if not accomplished, would materially and adversely impact the development of the Phase 2 expansion project. In light of this and other considerations, we are unable to predict whether or when Cameron LNG JV might be able to move forward on the Phase 2 expansion of the Cameron LNG JV liquefaction facility beyond
the first three trains.
The development of the potential Cameron LNG JV Phase 2 expansion project is subject to numerous other risks and uncertainties, including securing binding customer commitments; reaching unanimous agreement with our partners to proceed; obtaining a number of permits and regulatory approvals; securing financing; negotiating and completing suitable commercial agreements, including a definitive EPC contract, equity acquisition and governance agreements; reaching a final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors.”
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ECA LNG Liquefaction Export Projects
Sempra
LNG and IEnova are developing two natural gas liquefaction export projects at IEnova’s existing ECA Regas Facility. The liquefaction export projects, which are planned for development in two phases (a mid-scale project referred to as ECA LNG Phase 1 and a proposed large-scale project referred to as ECA LNG Phase 2), are being developed to provide buyers with direct access to North American west coast LNG supplies. We do not expect the construction of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility. However, construction of the ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has long-term regasification contracts for 100% of the regasification facility’s capacity through 2028, making the decisions on whether and how to pursue the ECA LNG Phase 2 project dependent in part on whether the investment in a large-scale liquefaction facility would, over the long term, be more beneficial
financially than continuing to supply regasification services under our existing contracts. We have planned measures to not disrupt operations at the ECA Regas Facility with the construction of the ECA LNG Phase 1 project.
In March 2019, ECA LNG received two authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from its ECA LNG Phase 1 project, which is a one-train natural gas liquefaction facility with a nameplate capacity of 3.25 Mtpa and initial offtake capacity of approximately 2.5 Mtpa that is under construction, and its proposed ECA LNG Phase 2 project that is in development.
In April 2020, ECA LNG Phase 1 executed definitive 20-year LNG sale and purchase agreements with Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG and with an affiliate of TOTAL SE for approximately 1.7 Mtpa of LNG. In December 2020,
an affiliate of TOTAL SE acquired a 16.6% ownership interest in ECA LNG Phase 1, with Sempra LNG and IEnova each retaining a 41.7% ownership interest. Our MOU with Mitsui & Co., Ltd. provides a framework for Mitsui & Co., Ltd.’s potential offtake of LNG from, and potential acquisition of an equity interest in, ECA LNG Phase 2.
In February 2020, we entered into an EPC contract with TechnipFMC for the engineering, procurement and construction of the ECA LNG Phase 1 project. Since reaching a final investment decision with respect to the project in November 2020, we released TechnipFMC to commence work to construct the ECA LNG Phase 1 project. The total price of the EPC contract is estimated at approximately $1.5 billion. We estimate that capital expenditures will approximate $2.0 billion, including capitalized interest and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures
may differ, perhaps substantially, from our estimates.
In December 2020, ECA LNG Phase 1 entered into a five-year loan agreement for an aggregate principal amount of up to $1.6 billion, of which $17 million was outstanding at December 31, 2020. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project. We discuss the details of this loan in Note 7 of the Notes to Consolidated Financial Statements.
The construction of the ECA LNG Phase 1 project and the development of the potential ECA LNG Phase 2 project are subject to numerous risks and uncertainties. For Phase 1, these include maintaining permits and regulatory approvals; construction delays; securing and maintaining commercial arrangements, such as gas supply and transportation agreements; and other factors associated with the project
and its construction. For Phase 2, these include obtaining binding customer commitments; the receipt of a number of permits and regulatory approvals; obtaining financing; negotiating and completing suitable commercial agreements, including a definitive EPC contract, equity acquisition and governance agreements, LNG sales agreements and gas supply and transportation agreements; reaching a final investment decision; and other factors associated with this potential investment. In addition, as we discuss in Note 16 of the Notes to Consolidated Financial Statements, an unfavorable decision on certain property disputes or permit challenges, or an extended dispute with existing customers at the ECA Regas Facility, could materially and adversely affect the development of these projects and Sempra Energy’s financial condition, results of operations, cash flows and prospects, including the impairment of all or a substantial portion of the capital costs invested in the projects
to date. For a discussion of these risks, see “Part I – Item 1A. Risk Factors.”
Port Arthur LNG Liquefaction Export Project
Sempra LNG is developing a proposed natural gas liquefaction export project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. Sempra LNG received authorizations from the DOE in August 2015 and May 2019 that collectively permit the LNG to be produced from the proposed Port Arthur LNG project to be exported to all current and future FTA and non-FTA countries.
In April 2019, the FERC approved the siting, construction and operation of the proposed Port Arthur LNG liquefaction facility, along with certain natural gas pipelines, including the Louisiana Connector and Texas Connector Pipelines, that could be used to supply feed gas to the liquefaction
facility, assuming the project is completed. In February 2020, Sempra LNG filed a FERC application for the siting, construction and operation of a second phase at the proposed Port Arthur LNG facility, including the potential addition of two liquefaction trains.
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In February 2020, we entered into an EPC contract with Bechtel for the proposed Port Arthur LNG liquefaction project. The EPC contract contemplates the construction of two liquefaction trains with a nameplate capacity of approximately 13.5 Mtpa, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services. We have no obligation to move forward on the EPC contract, and we may release Bechtel to perform portions of the work
pursuant to limited notices to proceed. We plan to fully release Bechtel to perform all of the work to construct the Port Arthur LNG liquefaction export project only after we reach a final investment decision with respect to the project and after certain other conditions are met, including obtaining project financing. In December 2020, we amended and restated the EPC contract to reflect an estimated price of approximately $8.7 billion, depending on the timing of a full notice to proceed, which, if not issued by July 15, 2021, will require renegotiation of the EPC contract. Any changes to the EPC contract will require the agreement of both parties, which cannot be assured.
In December 2018, Polish Oil & Gas Company (PGNiG) and Port Arthur LNG entered into a definitive 20-year agreement for the sale and purchase of 2 Mtpa of LNG per year from the Port Arthur LNG liquefaction
export project. Under the agreement, LNG purchases by PGNiG from Port Arthur LNG will be made on a free-on-board basis, with PGNiG responsible for shipping the LNG from the Port Arthur facility to the final destination. Port Arthur LNG will manage the gas pipeline transportation, liquefaction processing and cargo loading. The agreement is subject to certain conditions precedent, including Port Arthur LNG making a positive final investment decision within certain agreed timelines. The failure of these conditions precedent to be satisfied or waived within the agreed timelines could result in the termination of the agreement.
In May 2019, Aramco Services Company and Sempra LNG signed a Heads of Agreement for the negotiation of a definitive 20-year LNG sale and purchase agreement for 5 Mtpa of LNG offtake from the Port Arthur LNG liquefaction export project. The Heads of Agreement also includes the negotiation of a potential 25%
equity investment in the project. In January 2020, Aramco Services Company and Sempra LNG signed an Interim Project Participation Agreement, which sets forth certain mechanisms for the parties to work towards receipt of corporate approvals to enter into and proceed with the transaction, execution of the transaction agreements and the fulfillment or waiver of the conditions precedent contemplated by these agreements, making a final investment decision and other pre-final investment decision activities. The Heads of Agreement and Interim Project Participation Agreement do not obligate the parties to ultimately execute any agreements or participate in the project.
In November 2019, Port Arthur LNG commenced the relocation and upgrade of approximately three miles of highway where the Port Arthur LNG liquefaction export project would be located.
We continue to work on completing all necessary
milestones so that we are prepared to make a final investment decision for the proposed Port Arthur LNG liquefaction export project when appropriate. The impact of the COVID-19 pandemic on the global economy and uncertainty in the energy and financial markets, among other reasons, have delayed the expected timing of our final investment decision until 2021.
Development of the Port Arthur LNG liquefaction export project is subject to a number of risks and uncertainties, including obtaining additional customer commitments; completing the required commercial agreements, such as equity acquisitions and governance agreements, LNG sales agreements and gas supply and transportation agreements; completing construction contracts; securing all necessary permits and approvals; obtaining financing and incentives; reaching a final investment decision; and other factors associated with the potential investment. An unfavorable outcome with
respect to any of these factors could have a material adverse effect on Sempra Energy’s financial condition, results of operations and prospects, including the impairment of all or a substantial portion of the capital costs invested in the project to date. For a discussion of these risks, see “Part I – Item 1A. Risk Factors.”
In December 2020, we announced our intention to sell NCI in Sempra Infrastructure Partners, which represents the combined businesses of Sempra LNG and IEnova. We expect to complete this transaction in the second quarter of 2021. We intend to use the expected proceeds from the proposed sale of NCI to fund capital investments to support additional growth opportunities and strengthen
our balance sheet by reducing debt.
The proposed sale of NCI in Sempra Infrastructure Partners will reduce our ownership interest in Sempra Infrastructure Partners. Any decrease in our ownership of Sempra Infrastructure Partners would also decrease our share of the cash flows, profits and other benefits these businesses currently or may in the future produce, which could materially adversely affect our results of operations, cash flows, financial condition and/or prospects.
Our ability to complete this transaction is subject to a number of risks, including, among others, the ability to identify a suitable partner to purchase such NCI; negotiate the terms of equity sale, shareholder and other governance agreements with such partner; and obtain governmental, regulatory and third-party consents and approvals and satisfy any other closing conditions to complete
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this
transaction. Although the structure and terms of this transaction remain to be determined, the governmental and regulatory authorities with jurisdiction over the transaction could seek to block or challenge it or could impose requirements or obligations as conditions to its approval. If any of these circumstances were to occur, or if we are not able to achieve all of the foregoing in a timely manner or on satisfactory terms, then the proposed transaction may be abandoned and our prospects could be materially adversely affected. This transaction is subject to a number of risks and uncertainties that we discuss further in “Part I – Item 1A. Risk Factors.”
Discontinued Operations
In April 2020, we completed the sale of our equity interests in our Peruvian
businesses for cash proceeds of $3,549 million, net of transaction costs and as adjusted for post-closing adjustments. In June 2020, we completed the sale of our equity interests in our Chilean businesses for cash proceeds of $2,216 million, net of transaction costs and as adjusted for post-closing adjustments.
Our utilities in South America historically provided relatively stable earnings and liquidity. We used a portion of the proceeds from the sales of these businesses to strengthen our balance sheet by repaying certain borrowings and repurchasing shares of our common stock, and we intend to use the remaining proceeds to focus on capital investment in North America to support additional growth opportunities. We expect the cash provided by earnings from our capital investments will exceed the absence of cash flows from these discontinued operations. However, there is no assurance that we will derive these anticipated benefits.
Further, there is no assurance that we will be able to redeploy the capital that we obtained from such sales in a way that results in cash flows or earnings exceeding those historically generated by these businesses.
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SOURCES AND USES OF CASH
The following tables include only significant changes in cash flow activities for each of our registrants.
CASH
FLOWS FROM OPERATING ACTIVITIES
(Dollars in millions)
Years ended December 31,
Sempra Energy Consolidated
SDG&E
SoCalGas
2020
$
2,591
$
1,389
$
1,526
2019
3,088
1,090
868
Change
$
(497)
$
299
$
658
Change
in intercompany activities with discontinued operations (including $403 dividends received from our South American businesses in 2019)
$
(378)
Net increase in Insurance Receivable for Aliso Canyon primarily due to $132 higher accruals and $94 lower insurance proceeds received
(228)
$
(228)
Change in
accounts receivable
(224)
$
(119)
(28)
Release of a regulatory liability related to 2016-2018 income tax expense forecasting differences
(175)
(86)
(89)
Change in bad debt regulatory assets
(84)
(51)
(33)
TCJA
revenue amortization
(82)
(44)
(38)
Increase in prepaid insurance premiums
(24)
Net increase in Reserves for Aliso Canyon Costs, current and noncurrent, due to $450 higher accruals and $129 lower payments
579
579
Distributions
of earnings from Cameron LNG JV in 2020
365
Change in net undercollected regulatory balancing accounts (including long-term amounts in regulatory assets)
352
29
323
SDG&E’s initial shareholder contribution to the Wildfire Fund in September 2019
323
323
Decrease
in funding for the Rabbi Trust
141
Higher net margin posted at Sempra LNG’s marketing operations
109
Change in income taxes receivable/payable, net
72
255
345
Change
in accounts payable
61
71
Higher distributions of earnings from Oncor Holdings
39
Higher (lower) net income, adjusted for noncash items included in earnings
39
35
(258)
Other
35
(19)
14
Change
in net cash flows from discontinued operations primarily due to $1,161 income taxes paid related to the sale of our South American businesses
(1,441)
$
(497)
$
299
$
658
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CASH
FLOWS FROM OPERATING ACTIVITIES (CONTINUED)
(Dollars in millions)
Years ended December 31,
Sempra Energy Consolidated
SDG&E
SoCalGas
2019
$
3,088
$
1,090
$
868
2018
3,516
1,584
1,013
Change
$
(428)
$
(494)
$
(145)
Change in net undercollected regulatory balancing accounts (including long-term amounts in regulatory assets)
$
(513)
$
(254)
$
(259)
SDG&E’s
initial shareholder contribution to the Wildfire Fund in September 2019
(323)
(323)
Change in income taxes receivable/payable, net, primarily due to higher payments
(254)
(149)
(170)
Net decrease in Reserve for Aliso Canyon Costs due to $119 higher payments and $81
lower accruals
(200)
(200)
Deferred revenue due to the TCJA at the California Utilities in 2018
(123)
(62)
(61)
Cash payments for operating leases in 2019
(101)
(33)
(27)
Decrease
in interest payable primarily due to higher payments
(86)
Higher contributions to Rabbi Trust
(81)
Higher net income, adjusted for noncash items included in earnings
442
266
336
Change
in intercompany activities with discontinued operations (including $334 higher dividends received from our South American businesses)
308
Change in long-term GHG obligations
185
174
Net decrease in Insurance Receivable for Aliso Canyon Costs due to $84 higher insurance proceeds received and $81 lower accruals
165
165
Higher
distributions of earnings from Oncor Holdings
97
Change in accounts payable
(78)
Lower (higher) purchases of GHG allowances
50
(43)
Other
(38)
11
18
Change
in net cash flows from discontinued operations
94
$
(428)
$
(494)
$
(145)
98
CASH
FLOWS FROM INVESTING ACTIVITIES
(Dollars in millions)
Years ended December 31,
Sempra Energy Consolidated
SDG&E
SoCalGas
2020
$
553
$
(1,934)
$
(1,843)
2019
(4,593)
(1,522)
(1,438)
Change
$
5,146
$
(412)
$
(405)
Contributions
to Oncor Holdings to fund Oncor’s purchase of InfraREIT in May 2019
$
1,067
Distribution from Cameron LNG JV in 2020
753
Contributions to Peruvian businesses in discontinued operations in 2019
583
Contributions
to Chilean businesses in discontinued operations in 2019
394
Acquisition of investment in Sharyland Holdings in May 2019
95
Increase in capital expenditures
(968)
$
(420)
$
(404)
Dividends
received from Peruvian businesses in discontinued operations in 2019
(583)
Net proceeds from the April 2019 sale of Sempra Renewables’ wind assets and investments
(569)
Dividends received from Chilean businesses in discontinued operations in 2019
(394)
Net
proceeds from the February 2019 sale of Sempra LNG’s non-utility natural gas storage assets
(322)
Loan to ESJ JV in 2020
(85)
Other
(8)
8
(1)
Change
in net cash flows from discontinued operations mainly due to $5,766 proceeds, net of transaction costs, offset by $502 cash sold from the sale of our South American businesses
5,183
$
5,146
$
(412)
$
(405)
2019
$
(4,593)
$
(1,522)
$
(1,438)
2018
(12,470)
(1,542)
(1,531)
Change
$
7,877
$
20
$
93
Acquisition
of investment in Oncor Holdings in March 2018
$
9,556
Dividends received from Peruvian businesses in discontinued operations in 2019
583
Dividends received from Chilean businesses in discontinued operations in 2019
394
Net
proceeds from sale of Sempra LNG’s non-utility natural gas storage assets
322
Lower expenditures for investments in Cameron LNG JV and IMG JV
245
Lower advances to unconsolidated affiliates
79
Higher
contributions to Oncor Holdings primarily to fund Oncor’s purchase of InfraREIT in May 2019
(1,357)
Lower net proceeds from sale of certain Sempra Renewables’ assets and investments ($569 in 2019 and $1,571 in 2018)
(1,002)
Contributions to Peruvian businesses in discontinued operations in 2019
(583)
Contributions
to Chilean businesses in discontinued operations in 2019
(394)
(Increase) decrease in capital expenditures
(164)
$
20
$
99
Acquisition of investment in Sharyland Holdings in May 2019
(95)
Other
40
(6)
Change
in net cash flows from discontinued operations
253
$
7,877
$
20
$
93
99
CASH
FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Years ended December 31,
Sempra Energy Consolidated
SDG&E
SoCalGas
2020
$
(2,373)
$
797
$
311
2019
1,475
405
562
Change
$
(3,848)
$
392
$
(251)
Change
in short-term debt, net
$
(2,415)
$
131
$
(891)
Net proceeds from issuances of common stock from settlement of forward sale agreements in 2019
(1,794)
Higher payments for commercial paper and other short-term
debt with maturities greater than 90 days
(1,341)
Higher payments on long-term debt and finance leases
(856)
(236)
(6)
Repurchase of common stock under ASR program in 2020
(500)
Higher
repurchases of IEnova stock held by NCI
(221)
Lower issuances of short-term debt with maturities greater than 90 days
(213)
(Higher) lower common dividends paid
(181)
(200)
50
Capital
contribution from OMEC LLC in 2019 to repay OMEC’s loan
(175)
(175)
Lower advances from unconsolidated affiliates
(91)
Equity contribution from Sempra Energy to fund initial shareholder contribution to the Wildfire Fund in September 2019
(322)
Higher
issuances of long-term debt
1,968
1,198
600
Net proceeds from issuance of series C preferred stock
891
Change in intercompany activities with discontinued operations primarily related to intercompany loans in 2019
266
Other
21
(4)
(4)
Change
in net cash flows from discontinued operations primarily from a $250 intercompany loan and $60 net increase in short-term debt in 2020 and $977 equity contribution from Sempra Energy, offset by $1,380 common dividends paid in 2019
793
$
(3,848)
$
392
$
(251)
2019
$
1,475
$
405
$
562
2018
8,850
(34)
528
Change
$
(7,375)
$
439
$
34
Higher issuances of long-term debt in 2018, including increases at Sempra Energy Consolidated primarily to fund the March 2018 acquisition of investment in Oncor Holdings and at SDG&E from issuance of a new loan by OMEC LLC to partially repay OMEC’s project financing loan
$
(4,826)
$
(218)
$
(600)
Net
proceeds from 2018 issuances of mandatory convertible preferred stock
(2,258)
Lower net proceeds from issuances of common stock primarily related to settlements of forward sale agreements
(442)
(Higher) lower payments on long-term debt and finance leases
(217)
218
494
(Higher)
lower common dividends paid
(169)
250
(100)
Change in intercompany activities with discontinued operations primarily related to intercompany loans
(157)
Higher payments for commercial paper and other short-term debt with maturities greater than 90 days
(108)
Increase
(decrease) in short-term debt, net
740
(249)
234
Higher issuances of commercial paper and other short-term debt with maturities greater than 90 days
195
Advances from unconsolidated affiliates
155
Higher
capital contributions from OMEC LLC to repay OMEC’s loan
110
110
Equity contribution from Sempra Energy to fund initial shareholder contribution to the Wildfire Fund in September 2019
322
Other
(31)
6
6
Change
in net cash flows from discontinued operations primarily from $1,311 common dividends paid offset by $977 equity contributions received in 2019
(367)
$
(7,375)
$
439
$
34
100
Expenditures
for PP&E
We invest the majority of our capital expenditures in the California Utilities, primarily for transmission and distribution improvements, including pipeline and wildfire safety. The following table summarizes by segment capital expenditures for the last three years.
In 2019 and 2018, we invested heavily in our Sempra Texas
Utilities, which included our March 2018 acquisition of Oncor Holdings and subsequent contributions to Oncor Holdings, primarily to fund Oncor’s purchase of InfraREIT in May 2019. The following table summarizes by segment our investments in various JVs, as well as business and asset acquisitions.
The amounts and timing of capital expenditures and certain investments are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC, the FERC and the PUCT, and various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors.” In 2021, we expect to make capital expenditures and investments of approximately $5.8 billion (which excludes capital expenditures that will be funded by unconsolidated entities), as summarized by segment in the following table.
We
expect the majority of our capital expenditures and investments in 2021 will relate to transmission and distribution improvements at our regulated public utilities, the ECA LNG Phase 1 liquefaction export project at Sempra LNG and construction of liquid fuels terminals at Sempra Mexico.
From 2021 through 2025, and subject to the factors described below, which could cause these estimates to vary substantially, Sempra Energy expects to make aggregate capital expenditures and investments of approximately $22.5 billion (which excludes
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capital expenditures that will be funded by unconsolidated entities), as follows: $9.6 billion at SDG&E, $9.2 billion at SoCalGas, $0.6 billion at Sempra Texas Utilities, $1.1 billion
at Sempra Mexico and $2.0 billion at Sempra LNG. Capital expenditure amounts include capitalized interest and AFUDC related to debt.
Periodically, we review our construction, investment and financing programs and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, and safety and environmental requirements.
Our level of capital expenditures and investments in the next few years may vary substantially and will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in U.S. federal tax law and business opportunities providing desirable rates of return. See “Part I – Item 1A. Risk Factors” for a discussion of other factors that could affect future levels of our capital expenditures and investments. We intend to finance
our capital expenditures in a manner that will maintain our investment-grade credit ratings and capital structure, but there is no guarantee that we will be able to do so.
Capital Stock Transactions
Sempra Energy
Cash provided by issuances of common and preferred stock was:
▪$902 million in 2020
▪$1.8 billion in 2019
▪$4.5 billion in 2018
Sempra Energy Series C Preferred Stock Offering. In June 2020, we issued 900,000 shares of
our series C preferred stock in a registered public offering at a price to the public of $1,000 per share and received net proceeds of $889 million after deducting the underwriting discount and equity issuance costs of $11 million. We used the net proceeds for working capital and other general corporate purposes, including the repayment of indebtedness. We provide additional discussion about this equity offering in Note 13 of the Notes to Consolidated Financial Statements.
Sempra Energy Common Stock Repurchase Program. As we discuss in Note 14 of the Notes to Consolidated Financial Statements, in 2020, we entered into and completed an ASR program under which we paid $500 million to repurchase 4,089,375 shares of our common stock at an average price of $122.27 per share. We funded the $500 million share repurchase with a portion of the proceeds received from the sale of our South American businesses.
Dividends
Sempra
Energy
Sempra Energy paid cash dividends of:
▪$1,174 million for common stock and $157 million for preferred stock in 2020
▪$993 million for common stock and $142 million for preferred stock in 2019
▪$877 million for common stock and $89 million for preferred stock in 2018
On November 18, 2020, Sempra Energy declared a quarterly dividend of $1.045 per share of common stock, $1.50 per share of series A preferred stock and $1.6875 per share of series B preferred stock, all of which were paid on January 15, 2021.
Dividends
declared on common stock have increased in each of the last three years due to an increase in the per-share quarterly dividends approved by our board of directors to $1.045 in 2020 ($4.18 annually) from $0.9675 in 2019 ($3.87 annually) and from $0.895 in 2018 ($3.58 annually).
On February 23, 2021, our board of directors approved an increase in Sempra Energy’s quarterly common stock dividend to $1.10 per share ($4.40 annually), the first of which is payable April 15, 2021. In addition, on February 23, 2021, our board of directors declared quarterly dividends of $1.6875 per share on our series B preferred stock and semi-annual dividends of $24.375 per share on our series C preferred stock, both payable on April 15, 2021. All declarations
of dividends on our common stock and preferred stock are made at the discretion of the board of directors. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend on earnings, cash flows, financial and legal requirements, and other relevant factors at that time. As a result, Sempra Energy’s dividends on common stock declared on an annual historical basis, including recent historical increases, may not be indicative of future declarations.
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SDG&E
In 2020 and 2018, SDG&E paid common stock dividends to Enova and Enova paid corresponding dividends to Sempra Energy of $200 million and $250 million, respectively. SDG&E did not declare or pay common stock
dividends in 2019. SDG&E’s dividends on common stock declared on an annual historical basis may not be indicative of future declarations and could be impacted over the next few years in order for SDG&E to maintain its authorized capital structure while managing its capital investment program.
Enova, a wholly owned subsidiary of Sempra Energy, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova and dividends paid by Enova to Sempra Energy are eliminated in Sempra Energy’s consolidated financial statements.
SoCalGas
In 2020, 2019 and 2018, SoCalGas paid common stock dividends to PE and PE paid corresponding dividends to Sempra Energy of $100 million, $150 million and $50 million, respectively. SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative
of future declarations and could be impacted over the next few years in order for SoCalGas to maintain its authorized capital structure while managing its capital investment program.
PE, a wholly owned subsidiary of Sempra Energy, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to PE and dividends paid by PE to Sempra Energy are eliminated in Sempra Energy’s consolidated financial statements.
Dividend Restrictions
The board of directors for each of Sempra Energy, SDG&E and SoCalGas has the discretion to determine whether to declare and, if declared, the amount of any dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra Energy. At December 31,
2020, based on these regulations, Sempra Energy could have received combined loans and dividends of approximately $717 million from SDG&E and $148 million from SoCalGas.
We provide additional information about dividend restrictions in “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements.
Book Value Per Common Share
Sempra Energy’s book value per common share on the last day of each of the last three fiscal years was as follows:
▪$70.11 in 2020
▪$60.58 in 2019
▪$54.35
in 2018
The increase in 2020 was primarily due to comprehensive income exceeding dividends, offset by common stock repurchases. In 2019, the increase was primarily due to comprehensive income exceeding dividends and common stock issuances.
Capitalization
Our debt to capitalization ratio, calculated as total debt as a percentage of total debt and equity, was as follows:
TOTAL
CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIOS
Significant changes in 2020 that affected capitalization included the following:
▪Sempra Energy Consolidated: decrease in short-term debt and increase in equity from issuances of common and preferred stock and comprehensive income exceeding dividends.
▪SDG&E:
increase in long-term debt and increase in equity from comprehensive income exceeding dividends.
▪SoCalGas: increase in long-term debt and increase in equity from comprehensive income exceeding dividends.
COMMITMENTS
The following tables summarize undiscounted principal contractual commitments at December 31, 2020 for Sempra Energy Consolidated, SDG&E and SoCalGas. We provide additional information about commitments above and in Notes 1, 7, 9, 15 and 16 of the Notes to Consolidated Financial Statements.
UNDISCOUNTED
PRINCIPAL CONTRACTUAL COMMITMENTS – SEMPRA ENERGY CONSOLIDATED
Pension and other postretirement benefit obligations(4)
251
461
477
922
2,111
Wildfire
Fund obligation
13
26
26
38
103
Environmental commitments(5)
12
19
9
58
98
Other
70
44
24
98
236
Total
$
4,864
$
8,002
$
6,670
$
51,085
$
70,621
(1) We
calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps and cross-currency swaps. We calculate expected interest payments for variable-rate obligations based on forecast rates in effect at December 31, 2020.
(2)Includes $30 million of estimated variable payments.
(3) Sempra LNG has a sale and purchase agreement for the supply of LNG to the ECA Regas Facility. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2021 to 2029.
(4) Amounts represent expected company contributions to the plans for the next 10 years.
(5) Excludes
amounts related to the Leak that are recorded in Reserve for Aliso Canyon Costs and that are not currently known or reasonably estimable.
104
UNDISCOUNTED
PRINCIPAL CONTRACTUAL COMMITMENTS – SDG&E
Pension and other postretirement benefit obligations(2)
54
106
58
92
310
Wildfire
Fund obligation
13
26
26
38
103
Environmental commitments
2
4
4
46
56
Other
4
7
7
48
66
Total
$
1,820
$
2,751
$
1,970
$
17,423
$
23,964
(1) SDG&E
calculates expected interest payments using the stated interest rate for fixed-rate obligations. We calculate expected interest payments for variable-rate obligations based on forecast rates in effect at December 31, 2020.
(2) Amounts represent expected SDG&E contributions to the plans for the next 10 years.
UNDISCOUNTED
PRINCIPAL CONTRACTUAL COMMITMENTS – SOCALGAS
(Dollars in millions)
2021
2022 and 2023
2024 and 2025
Thereafter
Total
Long-term debt
$
—
$
300
$
850
$
3,609
$
4,759
Interest
on long-term debt(1)
167
334
303
2,115
2,919
Natural gas contracts
175
249
171
359
954
Operating
leases
19
30
20
8
77
Finance leases
12
18
17
12
59
Environmental
commitments(2)
10
15
5
11
41
Pension and other postretirement benefit obligations(3)
158
306
378
731
1,573
Asset
retirement obligations
59
134
140
10,240
10,573
Other
2
4
4
34
44
Total
$
602
$
1,390
$
1,888
$
17,119
$
20,999
(1) SoCalGas
calculates expected interest payments using the stated interest rate for fixed-rate obligations. We calculate expected interest payments for variable-rate obligations based on forecast rates in effect at December 31, 2020.
(2) Excludes amounts related to the Leak.
(3) Amounts represent expected SoCalGas contributions to the plans for the next 10 years.
The tables above exclude contracts between consolidated affiliates, intercompany debt and employment contracts.
The tables also exclude income tax liabilities at December 31, 2020 of:
▪$99
million for Sempra Energy Consolidated
▪$13 million for SDG&E
▪$68 million for SoCalGas
These liabilities relate to uncertain tax positions and were excluded from the tables because we are unable to reasonably estimate the timing and amount of future payments due to uncertainties in the effective settlement of tax positions. We provide additional information about unrecognized income tax benefits in Note 8 of the Notes to Consolidated Financial Statements.
We have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At December 31, 2020, we had approximately $508 million in standby letters of credit
outstanding under these agreements.
105
OFF-BALANCE SHEET ARRANGEMENTS
In August 2014 and December 2019, Sempra Energy provided guarantees for 50.2% of Cameron LNG JV’s financing obligations for a maximum amount of up to $4.0 billion. The guarantees will terminate upon satisfaction of certain conditions, including all three trains achieving financial completion by September 30, 2021 (with up to an additional 365-day extension beyond such date permitted in cases of force majeure). However, if Cameron LNG JV fails
to satisfy the financial completion criteria, a demand could be made under the guarantee for Sempra Energy’s 50.2% share of Cameron LNG JV’s obligations under the financing arrangements then due and payable, which could have a material adverse impact on Sempra Energy’s liquidity. We discuss these guarantees above in “Overview – Sempra LNG – Cameron LNG JV Three-Train Liquefaction Project (Phase 1),” in Note 6 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.”
In July 2020, Sempra Energy entered into a Support Agreement, which contains a guarantee and represents a variable interest, for the benefit of CFIN with a maximum exposure to loss of $979 million. The guarantee will terminate upon full repayment of the guaranteed debt by 2039, including repayment following an event in which the guaranteed debt is put to Sempra Energy. We discuss this guarantee in Notes 1, 6 and 12 of
the Notes to Consolidated Financial Statements.
SDG&E has entered into PPAs and tolling agreements that are variable interests. Our investments in Oncor Holdings and Cameron LNG JV are variable interests. Sempra Energy’s other businesses may also enter into arrangements that could include variable interests. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
Management views certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates.
We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements. We discuss choices among alternative accounting policies that are material to our financial statements and information concerning significant estimates with the Audit Committee of the Sempra Energy board of directors.
CONTINGENCIES
Sempra Energy, SDG&E, SoCalGas
We accrue losses for the estimated impacts of various conditions, situations or circumstances
involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and:
▪information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events
▪the amount of the loss 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.
Details of our issues in this area are discussed in Note 16 of the Notes to Consolidated Financial Statements.
REGULATORY ACCOUNTING
Sempra
Energy, SDG&E, SoCalGas
As regulated entities, the California Utilities’ customer rates, as set and monitored by regulators, are designed to recover the cost of providing service and provide the opportunity to earn a reasonable return on their investments. The California Utilities record 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 that asset from customers in future rates. Similarly, regulatory liabilities are recorded for amounts recovered in rates in advance or in excess of costs incurred. The California Utilities assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as:
▪changes in the regulatory and
political environment or the utility’s competitive position
106
▪issuance of a regulatory commission order
▪passage of new legislation
To the extent that circumstances associated with regulatory balances change, the regulatory balances are evaluated and adjusted if appropriate.
Adverse legislative or regulatory actions could materially impact the amounts of our regulatory assets and liabilities and could materially adversely impact our financial statements. Details of the California Utilities’ regulatory assets and liabilities and additional factors that management considers
when assessing probabilities associated with regulatory balances are discussed in Notes 1, 4, 15 and 16 of the Notes to Consolidated Financial Statements.
INCOME TAXES
Sempra Energy, SDG&E, SoCalGas
Our income tax expense and related balance sheet amounts involve significant management judgments and estimates. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. When we evaluate the anticipated resolution of income tax issues, we consider:
▪past resolutions of the same or similar issue
▪the status of any income tax
examination in progress
▪positions taken by taxing authorities with other taxpayers with similar issues
The likelihood of deferred income tax recovery is based on analyses of the deferred income tax assets and our expectation of future taxable income, based on our strategic planning.
Actual income taxes could vary from estimated amounts because of:
▪future impacts of various items, including changes in tax laws, regulations, interpretations and rulings
▪our financial condition in future periods
▪the resolution of various income tax issues between us and taxing
and regulatory authorities
For an uncertain position to qualify for benefit recognition, the position must 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%. If we do not have a more-likely-than-not position with respect to a tax position, then we do not recognize any of the potential tax benefit associated with the position. A tax position that meets the more-likely-than-not recognition is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon the effective resolution of the tax position.
Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments
to recorded amounts and may affect our results of operations, financial position and cash flows.
We discuss details of our issues in this area and additional information related to accounting for income taxes, including uncertainty in income taxes, in Note 8 of the Notes to Consolidated Financial Statements.
DERIVATIVES AND HEDGE ACCOUNTING
Sempra Energy, SDG&E, SoCalGas
We record derivative instruments for which we do not apply a scope exception at fair value on the balance sheet. Depending on the purpose for the contract and the applicability of hedge or regulatory accounting, the changes in fair value of derivatives may be recorded in earnings, on the balance sheet, or in OCI. We also use the normal purchase or sale exception for certain derivative contracts. Whenever possible, we use
exchange quoted prices or other third-party pricing to estimate fair values; if no such data is available, we use internally developed models and other techniques. The assumed collectability of derivative assets considers events specific to a given counterparty, the counterparty’s credit worthiness, and the tenor of the transaction.
The application of hedge accounting and normal purchase or sale accounting for certain derivatives is determined on a contract-by-contract basis. Significant changes in assumptions in our cash flow hedges, such as the amount and/or timing of forecasted transactions, could cause unrealized gains or losses (mark-to-market) to be reclassified out of AOCI to earnings, which may
107
materially
impact our results of operations. Additionally, changes in assumed physical delivery on contracts for which we elected normal purchase or sale accounting may result in “tainting” of the election, which may (1) preclude us from making this election in future transactions and (2) impact Sempra Energy’s results of operations. The impacts of derivatives and hedge accounting on the California Utilities’ results of operations are typically not significant because regulatory accounting principles generally apply to their contracts. We provide details of our derivative instruments and our fair value approaches in Notes 11 and 12, respectively, of the Notes to Consolidated Financial Statements.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Sempra Energy, SDG&E, SoCalGas
To measure our pension and other postretirement obligations, costs
and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We review these assumptions annually and update when appropriate.
The critical assumptions used to develop the required estimates include the following key factors:
▪discount rates
▪expected return on plan assets
▪health care cost trend rates
▪mortality rates
▪rate of compensation increases
▪termination and retirement rates
▪utilization
of postretirement welfare benefits
▪payout elections (lump sum or annuity)
▪lump sum interest rates
The actuarial assumptions we use may differ materially from actual results due to:
▪return on plan assets
▪changing market and economic conditions
▪higher or lower withdrawal rates
▪longer or shorter participant life spans
▪more or fewer lump sum versus annuity payout elections made by plan participants
▪higher
or lower retirement rates
These differences, other than those related to the California Utilities’ plans, where rate recovery offsets the effects of the assumptions on earnings, may result in a significant impact to the amount of pension and other postretirement benefit expense we record. For plans other than those at the California Utilities, the approximate annual effect on earnings of a 100 bps increase or decrease in the assumed discount rate would be less than $1 million and the effect of a 100 bps increase or decrease in the assumed rate of return on plan assets would be less than $2 million. We provide details of our pension and other postretirement benefit plans in Note 9 of the Notes to Consolidated Financial Statements.
ASSET RETIREMENT OBLIGATIONS
Sempra Energy, SDG&E
SDG&E’s
legal AROs related to the decommissioning of SONGS are estimated based on a site-specific study performed no less than every three years. The estimate of the obligations includes:
▪estimated decommissioning costs, including labor, equipment, material and other disposal costs
▪inflation adjustment applied to estimated cash flows
▪discount rate based on a credit-adjusted risk-free rate
▪actual decommissioning costs, progress to date and expected duration of decommissioning activities
Changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions
to the estimated total cost associated with retiring the assets. SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear
108
decommissioning activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s NDT.
We provide additional detail in Note 15 of the Notes to Consolidated Financial Statements.
IMPAIRMENT TESTING OF LONG-LIVED ASSETS
Sempra Energy
Whenever
events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the asset. If so, we estimate the fair value of the asset to determine the extent to which carrying value exceeds fair value. For such an estimate, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful life of a long-lived asset and to determine our intent to use the asset. Our intent to use or dispose of a long-lived asset is subject to re-evaluation and can change over time.
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.
If an impairment
test is required, the fair value of a long-lived asset can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements.
IMPAIRMENT TESTING OF GOODWILL
Sempra Energy
On an annual basis or whenever events or changes in circumstances necessitate an evaluation, we consider whether goodwill may be impaired. For our annual goodwill impairment testing, we have the option to first make a qualitative assessment of whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances,
including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, 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 quantitative goodwill impairment test. If, after performing the quantitative goodwill impairment test, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.
When determining if goodwill is impaired, the fair value of the reporting unit can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a
goodwill impairment may or may not be required. When we perform the quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and compare that to its carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as a discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include:
109
▪consideration
of market transactions
▪future cash flows
▪the appropriate risk-adjusted discount rate
▪country risk
▪entity risk
In 2020, we performed a quantitative goodwill impairment test and determined that the estimated fair values of our reporting units in Mexico to which goodwill was allocated was substantially above their carrying values as of October 1, 2020, our goodwill impairment testing date. We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements.
CARRYING VALUE OF EQUITY METHOD INVESTMENTS
Sempra
Energy
We generally account for investments under the equity method when we have significant influence over, but do not have control of, the investee.
We consider whether the fair value of each equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. To help evaluate whether a decline in fair value below carrying value has occurred and if the decline is other than temporary, we may develop fair value estimates for the investment. Our fair value estimates are developed from the perspective of a knowledgeable market participant. In the absence of observable transactions in the marketplace for similar investments, we consider an income-based approach such as a discounted cash flow analysis or, with less weighting, the replacement cost of the underlying net assets. A discounted cash flow analysis may be based directly
on anticipated future distributions from the investment, or may be performed based on free cash flows generated within the entity and adjusted for our ownership share total. For certain investments, critical assumptions may include, but are not limited to, transportation rates for natural gas, the appropriate risk-adjusted discount rate and the availability and costs of natural gas and LNG.
In addition, for our indirect investment in Oncor, critical assumptions may also include the effects of ratemaking, such as the results of regulator decisions on rates and recovery of regulated investments and costs. The risk assumptions applied by other market participants to value the investments could vary significantly or the appropriate approaches could be weighted differently. These differences could impact whether or not the fair value of the investment is less than its carrying value, and if so, whether that condition is other than
temporary. This could result in an impairment charge and, in cases where an impairment charge has been recorded, additional loss or gain upon sale in the case of a sale transaction.
We provide additional details in Notes 6 and 12 of the Notes to Consolidated Financial Statements.
NEW ACCOUNTING STANDARDS
We discuss the relevant pronouncements that have recently had or may have a significant effect on our financial statements and/or disclosures in Note 2 of the Notes to Consolidated Financial Statements.
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the risk of erosion of our cash flows, earnings, asset values or equity due to adverse changes in commodity market prices, interest rates and foreign currency and inflation rates.
RISK POLICIES
Sempra 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 help ensure compliance with our stated energy risk management and trading policies. These activities
include, but are not limited to, monitoring of market positions that create credit, liquidity and market risk. The respective oversight organizations and committees are independent from energy procurement departments.
110
Along with other tools, we use VaR and liquidity metrics to measure our exposure to market risk associated with commodity portfolios. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. We use a variance-covariance VaR model at a 95% confidence level. A liquidity metric is intended to monitor the amount of financial resources needed for meeting potential margin calls as forward market prices move. VaR
and liquidity risk metrics are independently verified by the respective risk management oversight organizations.
The California Utilities use power and natural gas derivatives to manage electric and natural gas price risk associated with servicing load requirements. The use of power and natural gas derivatives is subject to certain limitations imposed by company policy and is in compliance with risk management and trading activity plans that have been filed with and approved by the CPUC. We discuss revenue recognition in Note 3 and additional market-risk information regarding derivative instruments in Note 11 of the Notes to Consolidated Financial Statements.
We have exposure to changes in commodity prices, interest rates and foreign currency and inflation rates. The following discussion of these primary market-risk exposures as of December 31,
2020 includes a discussion of how these exposures are managed.
COMMODITY PRICE RISK
Market risk related to physical commodities is created by volatility in the prices and basis of certain commodities. Our various subsidiaries are exposed, in varying degrees, to commodity price risk, primarily to prices in the natural gas and electricity markets. Our policy is to manage this risk within a framework that considers the specific markets and operating and regulatory environments of each subsidiary.
Sempra 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 an effort to optimize these assets. These transactions are typically priced based on market indices, but may also include fixed
price purchases and sales of commodities. Any residual exposure is monitored as described above. A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of our commodity-based derivatives for these segments at December 31, 2020 or 2019. 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, 2020, the total VaR of the California Utilities’ natural gas and electric positions was not material, and SDG&E’s power 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.
111
The table below shows the nominal amount of our debt:
(1) After
the effects of interest rate swaps. Before the effects of acquisition-related fair value adjustments and reductions for unamortized discount and debt issuance costs, and excluding finance lease obligations.
An interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings that would result from a hypothetical change in market interest rates. Earnings are affected by changes in interest rates on short-term debt and variable-rate long-term debt. If weighted-average interest rates on short-term debt outstanding at December 31, 2020 increased or decreased by 10%, the change in earnings over the 12-month period ending December 31, 2021 would be negligible. If interest rates increased or decreased by 10% on all variable-rate long-term debt
at December 31, 2020, after considering the effects of interest rate swaps, the change in earnings over the 12-month period ending December 31, 2021 would be negligible.
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 our foreign
currency and inflation exposures in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations.”
The hypothetical effect for every 10% appreciation in the U.S. dollar against the Mexican peso, in which we have operations and investments, are as follows:
HYPOTHETICAL EFFECTS FROM 10% STRENGTHENING OF U.S. DOLLAR (1)
(Dollars in millions)
Hypothetical effects
Translation of 2020 earnings to
U.S. dollars(2)
$
(2)
Transactional exposure(3)
115
Translation of net assets of foreign subsidiaries and investment in foreign entities(4)
(17)
(1) After the effects of foreign currency derivatives.
(2) Amount represents the impact to earnings for a change in the average exchange rate throughout the reporting period.
(3) Amount
primarily represents the effects of currency exchange rate movement from December 31, 2020 on monetary assets and liabilities and translation of non-U.S. deferred income tax balances at our Mexican subsidiaries.
(4) Amount represents the effects of currency exchange rate movement from December 31, 2020 that would be recorded to OCI at the end of the reporting period.
Monetary assets and liabilities at our Mexican subsidiaries and JVs that are denominated in U.S. dollars may fluctuate significantly throughout the year. These monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. Based on a net monetary liability position of $4.4
billion, including those related to our investments in JVs, at December 31, 2020, the hypothetical effect of a 10% increase in the Mexican inflation rate is
112
approximately $90 million lower earnings as a result of higher income tax expense for our consolidated subsidiaries, as well as lower equity earnings for our JVs.
We completed the sales of our South American businesses in 2020 and are no longer exposed to changes in foreign currency and inflation rates in Peru and Chile.
ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements are listed on the Index to Consolidated Financial Statements set forth on page F-1 of this annual report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
Sempra Energy, SDG&E, SoCalGas
Sempra Energy, SDG&E and SoCalGas maintain disclosure controls and procedures designed to ensure that information required to be disclosed in their respective reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to the management of each company, including each respective principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired
control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra Energy, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2020, 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 as of such date.
MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Sempra Energy, SDG&E, SoCalGas
The respective management of Sempra Energy, SDG&E and SoCalGas is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f).
Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra Energy, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on these evaluations, each
company’s management concluded that its internal control over financial reporting was effective as of December 31, 2020. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2020, as stated in their reports, which are included in this annual report on Form 10-K.
113
There have been no changes in any such company’s internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, such company’s internal control
over financial reporting.
114
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, 2020,
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, 2020, 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, 2020 of Sempra Energy and our report dated February 25, 2021 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.
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, 2020, 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, 2020, 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, 2020 of SDG&E and our report dated February 25, 2021 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.
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, 2020, 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, 2020, 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, 2020
of SoCalGas and our report dated February 25, 2021 expressed an unqualified opinion on those financial statements.
Basis for Opinion
SoCalGas’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on SoCalGas’ internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SoCalGas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We
conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Because SDG&E meets the conditions of General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this report with
a reduced disclosure format as permitted by General Instruction I(2), the information required by Part III – Items 10, 11, 12 and 13 below is not required for SDG&E. We have, however, provided the information required by Part III – Item 10 with respect to SDG&E’s executive officers in “Part I – Item 1. Business – Other Matters – Information About Our Executive Officers.”
ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
We provide the information required by Part III – Item 10 with respect to executive officers for Sempra Energy (other than information required by Item 405 of SEC Regulation S-K) and SoCalGas in “Part I – Item 1. Business – Other Matters – Information About Our Executive Officers.” For Sempra Energy, all other information required by Part III – Item 10 is incorporated by reference from “Corporate Governance,”“Share Ownership” and “Proposal 1: Election of Directors” in the proxy statement to be filed for its May 2021 annual meeting of shareholders. For SoCalGas, all other information required by Part III – Item 10 is incorporated by reference from its information statement to be filed for its June 2021 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. EXECUTIVE COMPENSATION
The information required by Part III – Item 11 is incorporated
by reference from “Corporate Governance” and “Executive Compensation,” including “Compensation Discussion and Analysis,”“Compensation and Talent Committee Report” and “Compensation Tables” in the proxy statement to be filed for the May 2021 annual meeting of shareholders for Sempra Energy and from the information statement to be filed for the June 2021 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.
ITEM
12. SECURITY OWNERSHIP 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, 2020, outstanding awards consisted of stock options and RSUs held by 460 employees.
The following table sets forth information regarding our equity compensation plans at December 31, 2020.
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EQUITY
COMPENSATION PLANS
Equity compensation plans approved by shareholders
Number of shares to be issued upon exercise of outstanding options, warrants and rights(1)
Weighted-average exercise price of outstanding options, warrants and rights(2)
Number of additional shares remaining available for future issuance(3)
2013
LTIP
1,087,964
$
106.76
—
2019 LTIP
514,969
$
149.12
6,927,284
(1)The 2013 LTIP consists of 243,177 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, 658,574 performance-based RSUs and 186,213 service-based RSUs. The 2019 LTIP consists of 122,218 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, 235,387 performance-based RSUs and 157,364 service-based RSUs. Each performance-based RSU granted under the 2013 LTIP and the 2019 LTIP represents the right to receive from zero to 2.0 shares of our common stock if applicable performance conditions are satisfied. For purposes of this table, the number of shares of common stock shown to be subject to each performance-based RSU is 1.0 share, which assumes performance conditions are satisfied at the target level.
(2)Represents the weighted-average
exercise price of the 243,177 and 122,218 outstanding options to purchase shares of our common stock under the 2013 LTIP and the 2019 LTIP, respectively.
(3)The number of shares available for future issuance is increased by the number of shares to which each participant would otherwise be entitled that are withheld or surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards, and is also increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares. No new awards may be granted under the 2013 LTIP.
We provide additional discussion of share-based compensation in Note 10 of the Notes to Consolidated Financial Statements.
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The security ownership information required by Part III – Item 12 is incorporated by reference from “Share Ownership” in the proxy statement to be filed for the May 2021 annual meeting of shareholders for Sempra Energy and from the information statement to be filed for the June 2021 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Part III – Item 13 is incorporated by reference from “Corporate Governance” in the proxy statement to be filed for the May 2021 annual meeting of shareholders for Sempra Energy and from the information statement to be filed for the June 2021 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.
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ITEM
14. PRINCIPAL 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 2020 and 2019.
PRINCIPAL
ACCOUNTANT FEES
(Dollars in thousands)
Sempra Energy Consolidated
SDG&E
SoCalGas
Fees
Percent of total
Fees
Percent of total
Fees
Percent
of total
2020:
Audit fees:
Consolidated
financial statements, internal controls audits and subsidiary audits
$
9,145
$
2,469
$
3,023
Regulatory filings and related services
827
100
55
Total
audit fees
9,972
82
%
2,569
86
%
3,078
90
%
Audit-related fees:
Employee
benefit plan audits
505
183
307
Other audit-related services(1)
1,494
137
—
Total
audit-related fees
1,999
17
320
11
307
9
Tax fees(2)
156
1
111
3
32
1
All
other fees(3)
22
—
—
—
—
—
Total fees
$
12,149
100
%
$
3,000
100
%
$
3,417
100
%
2019:
Audit
fees:
Consolidated financial statements, internal controls audits and subsidiary audits
$
10,568
$
2,804
$
2,789
Regulatory
filings and related services
466
45
45
Total audit fees
11,034
87
%
2,849
89
%
2,834
91
%
Audit-related
fees:
Employee benefit plan audits
517
162
286
Other
audit-related services(1)
883
99
10
Total audit-related fees
1,400
11
261
8
296
9
Tax
fees(2)
74
1
73
3
—
—
All other fees(3)
74
1
15
—
—
—
Total
fees
$
12,582
100
%
$
3,198
100
%
$
3,130
100
%
(1)Other
audit-related services in 2020 primarily relate to statutory audits, agreed upon procedures and permitted internal control advisory services. Other audit-related services in 2019 primarily relate to statutory audits and agreed upon procedures.
(2)Tax fees in 2020 relate to tax consulting and compliance services. Tax fees in 2019 relate to tax consulting services.
(3)All other fees relate to training and conferences.
The Audit Committee of Sempra 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. Jack T. Taylor, who chairs the committee, and Ms. Cynthia L. Walker, who is a member of the committee, are audit committee financial experts as defined by the rules of the SEC.
Except
where pre-approval is not required by SEC rules, Sempra 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 2020 and 2019. The committee’s pre-approval policies and procedures provide for the general pre-approval of specific types of services and give detailed guidance to
120
management as to the services that are eligible for general pre-approval, and they
require specific pre-approval of all other permitted services. For both types of pre-approval, the committee considers whether the services to be provided are consistent with maintaining the firm’s independence. The committee’s policies and procedures also delegate authority to the chair of the committee to address any requests for pre-approval of services between committee meetings, with any pre-approval decisions to be reported to the committee at its next scheduled meeting.
PART
IV.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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 F-1 of this annual report on Form 10-K.
2. FINANCIAL STATEMENT SCHEDULES
Schedule I is listed on the Index to Condensed Financial Information of Parent as set forth on page S-1 of this annual report on Form 10-K.
Any other schedule for which provision is made in SEC Regulation S-X is not required under the instructions contained therein, is inapplicable or the information is included in the Consolidated Financial Statements and Notes thereto in this annual report on Form 10-K.
The exhibits listed below relate to each registrant as indicated. Unless otherwise indicated, the exhibits that are incorporated by reference herein were filed under File Number 1-14201 (Sempra Energy), File Number 1-40 (Pacific Lighting Corporation), File Number 1-03779 (San Diego Gas & Electric Company) and/or File Number 1-01402 (Southern California Gas Company).
EXHIBIT
4 -- INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES
Certain instruments defining the rights of holders of long-term debt instruments are not required to be filed or incorporated by reference herein pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K. Each registrant agrees to furnish a copy of such instruments to the SEC upon request.
(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.
U. S. Department of Energy contract for disposal of spent nuclear fuel and/or high-level radioactive waste, entered into between the DOE and Southern California Edison Company, as agent for SDG&E and others;
Contract DE-CR01-83NE44418, dated June 10, 1983.
10-K
10N
(1)
EXHIBIT 14 -- CODE OF ETHICS
Sempra
Energy / San Diego Gas & Electric Company / Southern California Gas Company
XBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document.
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
ITEM
16. FORM 10-K SUMMARY
Not applicable.
133
Sempra Energy:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934 (the Act), this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
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.
Pursuant to the requirements of the Securities Exchange Act of 1934 (the Act), this report has been signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.
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.
135
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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant in the capacities and
on the dates indicated.
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, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, based on criteria established in Internal Control – Integrated Framework (2013)
issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2021 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 and Legal Contingencies Related to Aliso Canyon Gas Leak - Refer to Note 16 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
Sempra Energy has an insurance receivable of $445 million as of December 31,
2020 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 applicable insurance policies.
Additionally, Sempra Energy is named in various lawsuits related to the gas leak and the liabilities could be material. Sempra Energy’s accrual for civil litigation matters associated with the gas leak, inclusive of estimated legal costs, is included within its $451 million Reserve for Aliso Canyon Costs as of December 31, 2020.
F-2
We
identified the recoverability of the insurance receivable as a critical audit matter due to the management judgments required in assessing if, and to what degree, the coverage provided by applicable insurance policies would cover the types of costs included in the insurance claims submitted. Also, we identified the contingency accrual related to the civil litigation as a critical audit matter due to the management judgments required in assessing the probability and reasonable estimation of the potential liability related to the civil litigation. Auditing the probability of recovery of the insurance receivable and the contingency accrual related to the civil litigation required subjective auditor judgment and extensive audit effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the probability of recovery of the insurance receivable for
the costs related to the Aliso Canyon natural gas storage facility gas leak included the following, among others:
▪We tested the effectiveness of management’s internal controls over the costs included in the related insurance receivable and the evaluation of the recoverability of this insurance receivable.
▪With the assistance of an insurance specialist, we evaluated management’s judgments related to the determination of the recoverability of the insurance receivable by:
◦Evaluating the coverage provided by applicable insurance policies and evaluating the potential coverage available under such policies based on the nature of the underlying costs.
◦Evaluating the probability
of recovery of the insurance receivable by obtaining correspondence between Sempra Energy and the applicable insurers.
◦Evaluating the probability of recovery of the insurance receivable through inquiries with management and with external legal counsel of Sempra Energy and we evaluated whether the information provided was consistent with our other procedures.
◦Searching external sources for and considering any contradictory evidence to Sempra Energy’s accounting assessment of probability of recoverability of the insurance receivable.
Our audit procedures related to civil litigation matters included the following, among others:
▪We tested the effectiveness of management’s internal controls over (1) Sempra
Energy’s determination of whether a loss was probable and reasonably estimable and (2) the financial statement disclosures related to the gas leak.
▪We evaluated management’s judgments related to (1) whether a loss was probable and reasonably estimable and (2) whether additional losses are reasonably possible by inquiring of management and legal counsel of Sempra Energy regarding the amounts of probable and reasonably estimable losses.
▪We read a settlement offer and external information for any evidence that might contradict management’s assertions.
▪We read legal letters from external and internal legal counsel of Sempra Energy regarding information from settlement discussions and we evaluated whether the information therein was consistent with
the information obtained in our procedures.
▪We evaluated whether Sempra Energy’s disclosures were appropriate and consistent with the information obtained in our procedures.
Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 1 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
Sempra 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:
F-3
▪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 precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
▪We evaluated Sempra Energy’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
We have served as Sempra Energy’s auditor since 1935.
F-4
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, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2020, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SDG&E’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2021 expressed an unqualified opinion on SDG&E’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility
of SDG&E’s management. Our responsibility is to express an opinion on SDG&E’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to SDG&E in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding
the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit
matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 1 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
SDG&E is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement
line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
F-5
How
the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We
read relevant regulatory orders issued by the Commissions for SDG&E and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
▪We evaluated SDG&E’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
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, 2020 and
2019, the related statements of operations, comprehensive income (loss), changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We have also audited, in accordance
with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), SoCalGas’ internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2021 expressed an unqualified opinion on SoCalGas’ internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of SoCalGas’ management. Our responsibility is to express an opinion on SoCalGas’ financial statements based on our audits. We are a public accounting firm registered with the PCAOB and
are required to be independent with respect to SoCalGas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating
the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Insurance Receivable
and Legal Contingencies Related to Aliso Canyon Gas Leak - Refer to Note 16 of the Notes to Financial Statements
Critical Audit Matter Description
SoCalGas has an insurance receivable of $445 million as of December 31, 2020 related to certain costs arising from the Aliso Canyon natural gas storage facility gas leak. SoCalGas has determined that the insurance receivable is probable of recovery based on the nature of the insurance claims, the costs incurred, and the coverage provided by applicable insurance policies.
Additionally, SoCalGas is named in various lawsuits related to the gas leak and the liabilities could be material. SoCalGas’ accrual for civil litigation matters associated with the gas leak, inclusive of estimated legal costs, is included within its $451 million Reserve for Aliso
Canyon Costs as of December 31, 2020.
We identified the recoverability of the insurance receivable as a critical audit matter due to the management judgments required in assessing if, and to what degree, the coverage provided by applicable insurance policies would cover the types of costs included in the insurance claims submitted. Also, we identified the contingency accrual related to the civil litigation as a critical audit matter due to the management judgments required in assessing the probability and reasonable estimation of the potential liability related to the civil litigation. Auditing the probability of recovery of the insurance receivable and the contingency accrual related to the civil litigation required subjective auditor judgment and extensive audit effort.
F-7
How
the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the probability of recovery of the insurance receivable for the costs related to the Aliso Canyon natural gas storage facility gas leak included the following, among others:
▪We tested the effectiveness of management’s internal controls over the costs included in the related insurance receivable and the evaluation of the recoverability of this insurance receivable.
▪With the assistance of an insurance specialist, we evaluated management’s judgments related to the determination of the recoverability of the insurance receivable by:
◦Evaluating the coverage provided by applicable insurance policies and evaluating the potential
coverage available under such policies based on the nature of the underlying costs.
◦Evaluating the probability of recovery of the insurance receivable by obtaining correspondence between SoCalGas and the applicable insurers.
◦Evaluating the probability of recovery of the insurance receivable through inquiries with management and with external legal counsel of SoCalGas and we evaluated whether the information provided was consistent with our other procedures.
◦Searching external sources for and considering any contradictory evidence to SoCalGas’ accounting assessment of probability of recoverability of the insurance receivable.
Our audit procedures related to civil litigation matters included the following,
among others:
▪We tested the effectiveness of management’s internal controls over (1) SoCalGas’ determination of whether a loss was probable and reasonably estimable and (2) the financial statement disclosures related to the gas leak.
▪We evaluated management’s judgments related to (1) whether a loss was probable and reasonably estimable and (2) whether additional losses are reasonably possible by inquiring of management and legal counsel of Sempra Energy and SoCalGas regarding the amounts of probable and reasonably estimable losses.
▪We read a settlement offer and external information for any evidence that might contradict management’s assertions.
▪We read legal letters
from external and internal legal counsel of Sempra Energy regarding information from settlement discussions and we evaluated whether the information therein was consistent with the information obtained in our procedures.
▪We evaluated whether SoCalGas’ disclosures were appropriate and consistent with the information obtained in our procedures.
Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 1 of the Notes to Financial Statements
Critical Audit Matter Description
SoCalGas is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of gas transmission and distribution companies in those jurisdictions. Management
has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing
these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities
and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We read relevant regulatory orders issued by the Commissions for SoCalGas and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
F-8
▪We evaluated SoCalGas’ disclosures related to the impacts of rate
regulation, including the balances recorded and regulatory developments.
NOTE
1. iSIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA
i
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 our subsidiaries that are not subject to California or Texas utility regulation. Sempra Energy’s businesses were managed within isix separate reportable segments until April 2019 and ifive
separate reportable segments thereafter, which we discuss in Note 17. All references in these Notes to our reportable segments are not intended to refer to any legal entity with the same or similar name.
SDG&E
SDG&E’s Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E was the primary beneficiary until August 23, 2019, at which time SDG&E deconsolidated the VIE, as we discuss below in “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra 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.
/i
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,”“us” 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 these Notes, we refer to the following as Consolidated Financial Statements and Notes to Consolidated Financial Statements when discussed together or collectively:
▪the Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;
▪the Consolidated Financial Statements and related Notes of SDG&E and its VIE (until deconsolidation of the VIE in August 2019); and
▪the Financial Statements and related Notes of SoCalGas.
i
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.
i
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, which we discuss further in Note 5. We completed the sales in the second quarter of 2020. Our discussions in the Notes below relate only to our continuing operations unless otherwise noted.
iSubsequent
Events
F-30
We evaluated events and transactions that occurred after December 31, 2020 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.
i
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:
▪the nature of the event giving rise to the assessment
▪existing statutes and regulatory code
▪legal precedents
▪regulatory
principles and analogous regulatory actions
▪testimony presented in regulatory hearings
▪regulatory orders
▪a commission-authorized mechanism established for the accumulation of costs
▪status of applications for rehearings or state court appeals
▪specific approval from a commission
▪historical experience
Sempra 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, 2020, owns an i80.25% interest in Oncor, and Sharyland Holdings, which owns i100%
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.”
/
i
FAIR
VALUE MEASUREMENTS
We measure certain assets and liabilities at fair value on a recurring basis, primarily NDT and benefit plan trust assets and derivatives. We also measure certain assets at fair value on a non-recurring basis in certain circumstances.
A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.
F-31
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:
▪quoted forward prices for commodities
▪time value
▪current market and contractual prices for the underlying instruments
▪volatility factors
▪other relevant economic measures
Substantially
all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions at SDG&E and the
Support Agreement at Sempra LNG.
i
CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.
Restricted cash includes 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 at Sempra Mexico.
i
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.
RECONCILIATION
OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash,
cash equivalents and restricted cash in discontinued operations
i—
i75
Total
cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows
$
i985
$
i217
/
In
the Sempra Energy Consolidated Statement of Cash Flows for the year ended December 31, 2020, the ending cash, cash equivalents and restricted cash balance in discontinued operations of $i4.6 billion is considered to be cash, cash equivalents and restricted cash for continuing operations following the sales of the South American businesses.
i
CREDIT
LOSSES
We are exposed to credit losses from financial assets measured at amortized cost, including trade and other accounts receivable and amounts due from unconsolidated affiliates. We are also exposed to credit losses from off-balance sheet arrangements through our guarantees of Cameron LNG JV’s debt.
F-32
We regularly monitor and evaluate credit losses and record allowances for expected credit losses, if necessary, for trade and other accounts receivable using a combination of factors, including past-due status based on contractual terms, trends in write-offs, the age of the receivable, historical and industry trends, counterparty creditworthiness, economic conditions and
specific events, such as bankruptcies. We write off financial assets measured at amortized cost in the period in which we determine they are not recoverable. We record recoveries of amounts previously written off when it is known that they will be recovered.
In connection with the COVID-19 pandemic, the California Utilities have implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for residential and small business customers, waiving late payment fees for business customers, and offering flexible payment plans to customers experiencing difficulty paying their electric or gas bills. As we discuss in Note 4, the CPUC authorized each of the California Utilities to track and request recovery of incremental costs, including uncollectible expenses, associated with complying with residential and small business customer protection measures implemented by the CPUC related to
the COVID-19 pandemic.
In June 2020, the CPUC issued a decision in a separate proceeding addressing service disconnections that, among other things, allows each of the California Utilities to establish a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills. This decision also directs the California Utilities to establish an AMP that provides successfully participating, income-qualified residential customers with relief from outstanding utility bill amounts. Refer to Note 4 for further discussion.
The California Utilities have recorded increases in their allowances for expected credit losses as of December 31, 2020 primarily related to expected forgiveness of outstanding utility bill amounts, including increases due to the effect of the COVID-19
pandemic, for residential customers eligible under the AMP. Our businesses will continue to monitor macroeconomic factors and customer payment patterns when evaluating their allowances for credit losses in future reporting periods, which may increase significantly due to the effects of the COVID-19 pandemic or other factors.
We provide below allowances and changes in allowances for credit losses for trade and other accounts receivable, excluding allowances related to amounts due from unconsolidated affiliates and off-balance sheet arrangements, which we discuss separately below the table. The California Utilities record changes in the allowances for credit losses related to Accounts Receivable – Trade in regulatory accounts.
i
TRADE
AND OTHER ACCOUNTS RECEIVABLE – ALLOWANCES FOR CREDIT LOSSES
Incremental
allowance upon adoption of ASU 2016-13
i1
i—
i—
Provisions
for expected credit losses
i124
i22
i10
Write-offs
(i16)
(i14)
(i14)
Allowances
for credit losses at December 31(1)
$
i138
$
i29
$
i21
SDG&E:
Allowances
for credit losses at January 1
$
i14
$
i11
$
i9
Provisions
for expected credit losses
i65
i10
i9
Write-offs
(i10)
(i7)
(i7)
Allowances
for credit losses at December 31(2)
$
i69
$
i14
$
i11
SoCalGas:
Allowances
for credit losses at January 1
$
i15
$
i10
$
i16
Provisions
for expected credit losses
i59
i12
i1
Write-offs
(i6)
(i7)
(i7)
Allowances
for credit losses at December 31(3)
$
i68
$
i15
$
i10
(1)Balances at December 31, 2020 and 2019 include $i111 million and $i7 million,
respectively, in Accounts Receivable – Trade, Net and $i27 million and $i22 million, respectively, in Accounts Receivable
– Other, Net.
(2)Balances at December 31, 2020 and 2019 include $i55 million and $i4 million,
respectively, in Accounts Receivable – Trade, Net and $i14 million and $i10 million, respectively, in Accounts Receivable
– Other, Net.
/
(3)Balances at December 31, 2020 and 2019 include $i55 million and $i3 million,
respectively, in Accounts Receivable – Trade, Net and $i13 million and $i12 million, respectively, in Accounts Receivable
– Other, Net.
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For amounts due from unconsolidated affiliates and off-balance sheet arrangements, on a quarterly basis, we evaluate credit losses and record allowances for expected credit losses, if necessary, based on credit quality indicators such as external credit ratings, published default rate studies, the maturity date of the instrument and past delinquencies. However, we do not record allowances for expected credit losses related to accrued interest receivable on loans due from unconsolidated affiliates because we write off such amounts, if any, through a reversal of interest income in the period we determine such amounts are uncollectible. In the absence of external credit
ratings, we may utilize an internally developed credit rating based on our analysis of a counterparty’s financial statements to determine our expected credit losses.
As we discuss below in “Transactions with Affiliates,” we have loans due from unconsolidated affiliates with varying tenors, interest rates and currencies. iWe provide below the changes in allowances for credit losses for loans and other amounts due from unconsolidated affiliates.
AMOUNTS
DUE FROM UNCONSOLIDATED AFFILIATES – ALLOWANCES FOR CREDIT LOSSES
(1) Balance at December 31, 2020 includes negligible amounts and $i3 million
in Due from Unconsolidated Affiliates – Current and Due from Unconsolidated Affiliates – Noncurrent, respectively.
As we discuss in Note 6, Sempra Energy has provided guarantees for the benefit of Cameron LNG JV related to its debt obligations for a maximum aggregate amount of $i4.0 billion. We established a liability for credit losses of $i6 million
for this off-balance sheet arrangement upon adoption of ASU 2016-13 on January 1, 2020 and we subsequently reduced this liability by $i4 million in the year ended December 31, 2020 through a reduction to credit loss expense, which is included in O&M on the Sempra Energy Consolidated Statement of Operations. At December 31, 2020, expected
credit losses of $i2 million are included in Other Current Liabilities on the Sempra Energy Consolidated Balance Sheet.
CONCENTRATION OF CREDIT RISK
Credit risk is the risk of loss that would be incurred as a result of nonperformance by our counterparties on their contractual obligations. We have policies governing the management of credit risk that are administered by the respective credit departments at each of our segments and overseen by their separate risk management
committees.
This oversight includes calculating current and potential credit risk on a regular basis and monitoring actual balances in comparison to approved limits. We establish credit limits based on risk and return considerations under terms customarily available in the industry. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of:
▪the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty
▪downgrade
triggers
We believe that we have provided adequate reserves for counterparty nonperformance in our allowances for credit losses.
When our development projects become operational, we rely significantly on the ability of suppliers to perform under long-term agreements and on our ability to enforce contract terms in the event of nonperformance. Also, the factors that we consider in evaluating a development project include negotiating customer and supplier agreements and, therefore, we rely on these agreements for future performance. We also may condition our decision to go forward on development projects on first obtaining these customer and supplier agreements.
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INVENTORIES
The
California Utilities value natural gas inventory using the last-in first-out method. As inventories are sold, differences between the last-in first-out valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. 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.
i
The
components of inventories are as follows:
INVENTORY
BALANCES AT DECEMBER 31
(Dollars in millions)
Natural gas
LNG
Materials and supplies
Total
2020
2019
2020
2019
2020
2019
2020
2019
Sempra
Energy Consolidated
$
i118
$
i110
$
i7
$
i9
$
i183
$
i158
$
i308
$
i277
SDG&E
i—
i1
i—
i—
i104
i93
i104
i94
SoCalGas
i94
i90
i—
i—
i59
i46
i153
i136
/
WILDFIRE
FUND
In July 2019, the Wildfire Legislation was signed into law. The Wildfire Legislation addresses certain issues related to catastrophic wildfires in the State of California and their impact on electric IOUs. Investor-owned gas distribution utilities such as SoCalGas are not covered by this legislation. The issues addressed include wildfire mitigation, cost recovery standards and requirements, a wildfire fund, a cap on liability, and the establishment of a wildfire safety board.
The Wildfire Legislation provided that SDG&E would not recover the ROE on its first $i215 million
of fire risk mitigation capital expenditures.
The Wildfire Legislation established a revised legal standard for the recovery of wildfire costs (Revised Prudent Manager Standard) and established a fund (the Wildfire Fund) designed to provide liquidity to SDG&E, PG&E and Edison to pay IOU wildfire-related claims in the event that the governmental agency responsible for determining causation determines the applicable IOU’s equipment caused the ignition of a wildfire, primary insurance coverage is exceeded and certain other conditions are satisfied. A primary purpose of the Wildfire Fund is to pool resources provided by shareholders and ratepayers of the IOUs and make those resources available to reimburse the IOUs for third-party wildfire claims incurred after July 12, 2019, the effective date of the Wildfire Legislation, subject to certain limitations.
An
IOU may seek payment from the Wildfire Fund for settled or adjudicated third-party damage claims arising from certain wildfires that exceed, in aggregate in a calendar year, the greater of $i1 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 i20% of the equity portion of an IOU’s electric transmission and distribution rate base in the year of the prudency determination.
Based on its 2020 rate base, the liability cap for SDG&E is approximately $i950 million, which is adjusted annually. The liability cap will apply on a rolling three-year basis so long as future annual safety certifications are received and the Wildfire Fund has not been terminated, which could occur if funds are exhausted. Amounts in excess of the liability cap and amounts that are determined to be prudently incurred do not need to be reimbursed by an IOU to the Wildfire Fund. The Wildfire Fund does not have a specified term and coverage will
continue until the assets of the
F-35
Wildfire Fund are exhausted and the Wildfire Fund is terminated, in which case, the remaining funds, if any, will be transferred to California’s general fund to be used for fire risk mitigation programs.
In June 2020, the CPUC approved SDG&E’s 2020 wildfire mitigation plan, which is effective until the CPUC approves a new plan. In addition, on September 14, 2020, SDG&E received its 2020 safety certification from the Wildfire Safety Division of the CPUC. The certificate is valid for 12 months from the issue date.
The Wildfire Fund has been initially funded up to $i10.5 billion
by a loan from the State of California Surplus Money Investment Fund. The loan is financed through a DWR bond, which was put in place on October 1, 2020 and is securitized through a dedicated surcharge on ratepayers’ bills attributable to the DWR. In October 2019, the CPUC adopted a decision authorizing a non-bypassable charge to be collected by the IOUs to support the anticipated DWR bond issuance authorized by AB 1054. The CPUC decision also determined that ratepayers of non-participating electrical corporations shall not pay the non-bypassable charge.
The Wildfire Fund has also been funded $i7.5 billion
from initial shareholder contributions from the IOUs (SDG&E’s share was $i322.5 million, PG&E’s share was $i4.8 billion
and Edison’s share was $i2.4 billion). The IOUs are also required to make annual shareholder contributions to the Wildfire Fund with an aggregate value of $i3 billion
over a i10-year period starting in 2019 (SDG&E’s share is $i129 million, PG&E’s share is $i1.9 billion
and Edison’s share is $i945 million). The contributions are not subject to rate recovery.
In a complaint filed in U.S. District Court for the Northern District of California in July 2019, plaintiffs seek to invalidate AB 1054 based on allegations that the legislation violates federal law. That court dismissed the complaint and the plaintiffs have petitioned the U.S. Court of Appeals for the Ninth Circuit to review the dismissal.
Wildfire
Fund Asset and Obligation
In the third quarter of 2019, SDG&E recorded both a Wildfire Fund asset and a related obligation of $i451.5 million for its commitment to make shareholder contributions to the Wildfire Fund, measured at present value as of July 25, 2019 (the date by which both Edison and SDG&E opted to contribute to the Wildfire Fund). SDG&E paid its initial shareholder contribution of $i322.5 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 and PG&E paid its initial shareholder contribution in July 2020 after receiving bankruptcy court approval to participate in the Wildfire Fund. SDG&E expects to make annual shareholder contributions of $i12.9 million
through December 31, 2028. SDG&E accretes the present value of the Wildfire Fund obligation until the liability is settled.
SDG&E is amortizing the Wildfire Fund asset on a straight-line basis over the estimated period of benefit, as adjusted for utilization by the IOUs. The estimated period of benefit of the Wildfire Fund asset is i15 years and is based on several assumptions, including, but not limited to:
•historical wildfire experience of
each IOU in the State of California, including frequency and severity of the wildfires
•the value of property potentially damaged by wildfires
•the effectiveness of wildfire risk mitigation efforts by each IOU
•liability cap of each IOU
•IOU prudency determination levels
•FERC jurisdictional allocation levels
•insurance coverage levels
The use of different assumptions, or changes to the assumptions used, could have a significant impact on the estimated period of benefit of the Wildfire Fund asset. SDG&E periodically
evaluates the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in these assumptions. SDG&E 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 any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, would decrease the Wildfire Fund asset and remaining available coverage. Although California experienced some of the largest wildfires in its history in 2020 (measured by acres burned), including fires in each participating IOU’s service territory, SDG&E is not aware of any claims made by any participating IOU requiring a reduction of the Wildfire Fund asset as of December 31, 2020.
F-36
i
The
following table summarizes the location of balances related to the Wildfire Fund on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets and Consolidated Statements of Operations.
Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax
basis of assets and liabilities. Investment tax credits from prior years are amortized to income by 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:
▪regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and
▪regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned to customers.
When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to
have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.
Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.
We accrue income tax to the extent we intend to repatriate cash to the U.S. from our continuing international operations. We
currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries 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.
i
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.
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RENEWABLE ENERGY CERTIFICATES
RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.
Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market
to comply with the RPS Program established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS Program. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.
i
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 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.
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i
PROPERTY,
PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(1) At
December 31, 2020, includes $i505 million in electric transmission assets and $i9 million in construction work
in progress related to SDG&E’s i88% 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
$i191 million and $i178 million at December 31, 2020 and 2019,
respectively, of utility plant, primarily pipelines and other distribution assets at Ecogas.
(3)Estimated useful lives are for land rights.
/
Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period for the California Utilities, or the remaining term of the site leases, whichever is shortest.
Electric
transmission, distribution and generation(1)
i5,145
i4,705
Total
SDG&E
i6,015
i5,537
SoCalGas:
Accumulated
depreciation:
Natural gas operations
i6,422
i6,023
Other
non-utility
i15
i15
Total
SoCalGas
i6,437
i6,038
Other
operating units and parent and other:
Accumulated depreciation – other(2)
i1,473
i1,302
Total
Sempra Energy Consolidated
$
i13,925
$
i12,877
(1) Includes
$i277 million at December 31, 2020 related to SDG&E’s i88%
interest in the Southwest Powerlink transmission line, jointly owned by SDG&E and other utilities.
(2) Includes $i51 million and $i49
million at December 31, 2020 and 2019, 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.
i
The table below summarizes capitalized interest and AFUDC.
Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized, but we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, we record a goodwill impairment loss as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.
F-40
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 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 quantitative goodwill impairment test. If, after performing the quantitative goodwill impairment test, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over
its fair value, not to exceed the carrying amount of goodwill.
Goodwill of $ii1,602/ million at December
31, 2020 and 2019 relates to the 2016 acquisitions of IEnova Pipelines and Ventika wind power generation facilities at Sempra Mexico.
Other Intangible Assets
i
Other Intangible Assets included on the Sempra Energy Consolidated Balance Sheets are as follows:
▪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.
Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for intangible assets in 2020, 2019 and 2018 was $i11
million, $i11 million and $i16 million, respectively. We estimate the amortization expense for the next five years to be $iiiii12////
million per year.
i
LONG-LIVED ASSETS
We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated
entities. A long-lived asset may be impaired when the estimated future undiscounted cash flows are less than the carrying amount of the asset. If that comparison indicates that the asset’s carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the asset. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
F-41
i
VARIABLE
INTEREST ENTITIES
We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based on qualitative and quantitative analyses, which assess:
▪the purpose and design of the VIE;
▪the nature of the VIE’s risks and the risks we absorb;
▪the power to direct activities that most significantly impact the economic performance of the VIE; and
▪the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.
We will continue to evaluate our VIEs for any changes that may impact our
determination of whether an entity is a VIE and if we are the primary beneficiary.
SDG&E
SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs that include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary.
SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities.
Based on our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which it considers the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If SDG&E
determines that it is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE.
In addition to tolling agreements, other variable interests involve various elements of fuel and power costs, and other components of cash flows expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities, including the operation and maintenance activities of the generating facility, that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects could be significant to the financial position and liquidity of SDG&E and Sempra Energy.
SDG&E
determined that none of its PPAs and tolling agreements resulted in SDG&E being the primary beneficiary of a VIE at December 31, 2020 and 2019. PPAs and tolling agreements that relate to SDG&E’s involvement with VIEs are primarily accounted for as finance leases. The carrying amounts of the assets and liabilities under these contracts are included in PP&E and finance lease liabilities with balances of $ii1,237/ million
and $ii1,255/ million at December
31, 2020 and 2019, respectively. SDG&E recovers costs incurred on PPAs, tolling agreements and other variable interests through CPUC-approved long-term power procurement plans. SDG&E has no residual interest in the respective entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 16. As a result, SDG&E’s potential exposure to loss from its variable interest in these VIEs is not significant.
Otay Mesa VIE
Through October 3, 2019, SDG&E had a tolling agreement to purchase power generated at OMEC, a i605-MW
generating facility owned by OMEC LLC, which is a VIE that we refer to as Otay Mesa VIE. SDG&E determined that it was the primary beneficiary of Otay Mesa VIE, and therefore, SDG&E and Sempra Energy consolidated Otay Mesa VIE. On August 23, 2019, SDG&E and OMEC LLC executed an amended resource adequacy capacity agreement that resulted in SDG&E and Sempra Energy deconsolidating Otay Mesa VIE. No gain or loss was recognized upon deconsolidation.
Sempra Texas Utilities
Our i100%
interest in Oncor Holdings is a VIE that owns an i80.25% 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
F-42
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 $i12,440 million and $i11,519
million at December 31, 2020 and 2019, respectively.
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. At December 31, 2019, Sempra Mexico consolidated such a VIE with assets totaling approximately $i126
million, which consisted primarily of PP&E and other long-term assets.
Sempra LNG
Cameron LNG JV
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, including LNG production and operation and maintenance activities at the liquefaction facility. Therefore, we account for our investment in Cameron LNG JV under the equity method. The carrying value of our investment, including amounts recognized in AOCI related to interest-rate cash flow hedges at Cameron LNG JV, was $i433
million at December 31, 2020 and $i1,256 million at December 31, 2019. Our maximum exposure to loss, which fluctuates over time, includes the carrying value of our investment and guarantees that we discuss in Note 6.
CFIN
As we discuss in Note 6, in July 2020, Sempra Energy entered into a Support Agreement for the benefit of CFIN, which is a VIE. Since we do not have the power to direct the most
significant activities of the VIE, we are not the primary beneficiary. The conditional obligations of the Support Agreement represent a variable interest that we measure at fair value on a recurring basis (see Note 12). Sempra Energy’s maximum exposure to loss under the terms of the Support Agreement is$i979 million.
ECA LNG Phase 1
ECA LNG Phase 1 is a VIE because its total equity at risk is not sufficient to finance
its activities without additional subordinated financial support. We expect that ECA LNG Phase 1 will require future capital contributions or other financial support to finance the construction of the facility. Sempra Energy is the primary beneficiary of the VIE because we have the power to direct the development activities related to the construction of the facility, which we consider to be the most significant activities of ECA LNG Phase 1 during the construction phase of the project. As a result, we consolidate ECA LNG Phase 1. At December 31, 2020, Sempra LNG consolidated $i207 million
of assets, consisting primarily of PP&E, attributable to ECA LNG Phase 1 that could be used only to settle obligations of the VIE and that are not available to settle obligations of Sempra Energy and $i49 million of liabilities, consisting primarily of accounts payable, attributable to ECA LNG Phase 1 for which creditors do not have recourse to the general credit of Sempra Energy. Additionally, as we discuss in Note 7, Sempra Energy, IEnova and TOTAL SE have provided guarantees for the loan facility based on their respective proportionate ownership interest in ECA LNG Phase 1.
i
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:
F-43
SDG&E and SoCalGas
▪fuel and storage tanks
▪natural gas transmission and distribution systems
▪hazardous waste storage facilities
▪asbestos-containing construction materials
SDG&E
▪nuclear
power facilities
▪electric transmission and distribution systems
▪energy storage systems
▪power generation plants
SoCalGas
▪underground natural gas storage facilities and wells
All Other Sempra Energy Businesses
▪natural gas transportation and distribution systems
▪power generation plants
▪LNG facility
▪LPG
terminal
i
The changes in AROs are as follows:
CHANGES
IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
Sempra Energy Consolidated
SDG&E
SoCalGas
2020
2019
2020
2019
2020
2019
Balance
as of January 1(1)
$
i3,083
$
i2,972
$
i866
$
i874
$
i2,177
$
i2,063
Accretion
expense
i127
i123
i39
i39
i86
i81
Liabilities
incurred
i2
i2
i—
i—
i—
i—
Deconsolidation
i—
(i2)
i—
(i2)
i—
i—
Payments
(i63)
(i46)
(i60)
(i44)
(i2)
(i2)
Revisions
i140
i34
i31
(i1)
i107
i35
Balance
at December 31(1)
$
i3,289
$
i3,083
$
i876
$
i866
$
i2,368
$
i2,177
(1) Current
portion of the ARO for Sempra Energy Consolidated is included in Other Current Liabilities on the Consolidated Balance Sheets.
/
i
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.
i
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.
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i
COMPREHENSIVE
INCOME
Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:
▪foreign currency translation adjustments
▪certain hedging activities
▪changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans
▪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.
iThe following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to NCI:
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CHANGES
IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
(Dollars in millions)
Foreign currency translation adjustments
Financial instruments
Pension and other postretirement benefits
Total accumulated other comprehensive income (loss)
(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 $i6 million in transfers of liabilities from SDG&E to SoCalGas and $i3
million in transfers of liabilities from SDG&E to Sempra Energy in 2020 and $i4 million in transfers of liabilities from SoCalGas to Sempra Energy in 2019 related to the nonqualified pension plans.
(4) Total AOCI includes $i4 million
of foreign currency translation adjustments and $i3 million of financial instruments associated with purchases of NCI, which we discuss below in “Other Noncontrolling Interests – Sempra Mexico,” and which does not impact the Consolidated Statement of Comprehensive Income (Loss).
F-46
i
RECLASSIFICATIONS
OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other comprehensive income (loss) components
Amounts reclassified from accumulated other comprehensive income (loss)
Affected line item on Consolidated Statements of Operations
Total
reclassifications for the period, net of tax
$
i721
$
i40
$
i21
SDG&E:
Financial
instruments:
Interest rate instruments(1)
$
i—
$
i3
$
i7
Interest
Expense
i—
(i3)
(i7)
Earnings
Attributable to Noncontrolling Interest
$
i—
$
i—
$
i—
Pension
and other postretirement benefits(2):
Amortization of actuarial loss
$
i1
$
i—
$
i1
Other
Income, Net
Amortization of prior service cost
i1
i1
i—
Other
Income, Net
Settlement charges
i—
i—
i4
Other
Income, Net
Total before income tax
i2
i1
i5
(i1)
i—
(i1)
Income
Tax Expense
Net of income tax
$
i1
$
i1
$
i4
Total
reclassifications for the period, net of tax
$
i1
$
i1
$
i4
SoCalGas:
Financial
instruments:
Interest rate instruments
$
i—
$
i1
$
i1
Interest
Expense
Pension and other postretirement benefits(2):
Amortization
of actuarial loss
$
i1
$
i1
$
i—
Other
(Expense) Income, Net
Amortization of prior service cost
i1
i—
i1
Other
(Expense) Income, Net
Total before income tax
i2
i1
i1
i—
(i1)
i—
Income
Tax Expense
Net of income tax
$
i2
$
i—
$
i1
Total
reclassifications for the period, net of tax
$
i2
$
i1
$
i2
(1) Amounts
in 2019 and 2018 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).
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F-47
i
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 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 was no longer the primary beneficiary of the VIE.
Sempra
Mexico
On December 2, 2020, we announced a non-binding offer to acquire up to i100% of the publicly held shares of IEnova in exchange for shares of our common stock at an exchange ratio of i0.0313
shares of our common stock for each one IEnova ordinary share. This exchange ratio is non-binding and remains subject to approval by Sempra Energy’s board of directors. We expect to complete this transaction in the second quarter of 2021, subject to authorization by the SEC, CNBV and Mexican Stock Exchange and other closing conditions.
In the first quarter of 2020, IEnova purchased additional shares in ICM Ventures Holdings B.V. for $i9 million, increasing its ownership interest from i53.7%
to i82.5%. ICM Ventures Holdings B.V. owns certain permits and land where IEnova is building terminals for the receipt, storage and delivery of liquid fuels.
In 2020, IEnova repurchased i77,122,780
shares of its outstanding common stock held by NCI for approximately $i231 million, resulting in an increase in Sempra Energy’s ownership interest in IEnova from i66.6%
to i70.2%.
In 2019, IEnova repurchased i2,620,000 shares of its outstanding common stock held
by NCI for approximately $i10 million, resulting in an increase in Sempra Energy’s ownership interest in IEnova from i66.5% to i66.6%.
Sempra
LNG
In December 2020, an affiliate of TOTAL SE acquired a i16.6% ownership interest in ECA LNG Phase 1, with Sempra LNG and IEnova each retaining a i41.7%
ownership interest. Sempra LNG consolidates ECA LNG Phase 1 and Sempra Energy’s NCI in IEnova’s i41.7% ownership interest is reported at Sempra LNG.
In March 2020, Sempra LNG purchased for $i7 million
the i24.6% minority interest in Liberty Gas Storage LLC, which owns i100% of LA Storage, LLC, increasing
Sempra LNG’s ownership in Liberty Gas Storage LLC to i100%. Prior to the purchase, the minority partner converted $i22 million
in notes payable due from Sempra LNG to equity. As a result of the purchase, we recorded an increase in Sempra Energy’s shareholders’ equity of $i2 million for the difference between the carrying value and fair value related to the change in ownership.
In February 2019, Sempra LNG purchased for $i20
million the i9.1% minority interest in Bay Gas immediately prior to the sale of i100%
of Bay Gas.
Sempra Renewables
As we discuss in Note 5, 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.
Discontinued Operations
As we discuss in Note 5, we completed the sales of our equity interests in our Peruvian and Chilean businesses in the second quarter of 2020. The minority interests in Luz del Sur and Tecsur were deconsolidated upon sale of our Peruvian businesses in April 2020, and the minority interests in the Chilquinta Energía subsidiaries were deconsolidated upon sale of our Chilean businesses in June 2020.
The following table provides information about NCI held by others
in subsidiaries or entities consolidated by us and recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Consolidated Balance Sheets.
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i
OTHER
NONCONTROLLING INTERESTS
(Dollars in millions)
Percent ownership held by noncontrolling interests
(1) IEnova
and Chilquinta Energía have subsidiaries with NCI held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.
/
REVENUES
See Note 3 for a description of significant accounting policies for revenues.
i
OPERATION
AND MAINTENANCE EXPENSES
Operation and Maintenance includes O&M and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, insurance, rent and litigation expense (except for litigation expense included in Aliso Canyon Litigation and Regulatory Matters).
i
FOREIGN CURRENCY TRANSLATION
AND TRANSACTIONS
Our natural gas distribution utility in Mexico, Ecogas, and the majority of our former operations in South America (until our sale of these operations in the second quarter of 2020) use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings, but are reflected in OCI and in AOCI.
Cash flows of these consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in Effect of Exchange Rate Changes
on Cash, Cash Equivalents and Restricted Cash on the Sempra Energy Consolidated Statements of Cash Flows.
Foreign currency transaction (losses) gains in a currency other than Sempra Mexico’s functional currency were $(i25) million, $i21
million and $(i6) million for the years ended December 31, 2020, 2019 and 2018, respectively, and are included in Other Income, Net, on the Sempra Energy Consolidated Statements of Operations. Foreign currency transaction gains (losses) in a currency other than the functional currencies of our operations in South America are included in discontinued operations.
F-49
i
TRANSACTIONS
WITH AFFILIATES
We summarize amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas in the following table.
Total
due to unconsolidated affiliates – noncurrent
$
(i234)
$
(i195)
SDG&E:
Sempra
Energy
$
(i38)
$
(i37)
SoCalGas
(i21)
(i10)
Various
affiliates
(i5)
(i6)
Total
due to unconsolidated affiliates – current
$
(i64)
$
(i53)
Income
taxes due from Sempra Energy(6)
$
i—
$
i130
SoCalGas:
SDG&E
$
i21
$
i10
Various
affiliates
i1
i1
Total
due from unconsolidated affiliates – current
$
i22
$
i11
Sempra
Energy
$
(i31)
$
(i45)
Various
affiliates
i—
(i2)
Total
due to unconsolidated affiliates – current
$
(i31)
$
(i47)
Income
taxes due (to) from Sempra Energy(6)
$
(i37)
$
i152
(1) Amounts
include principal balances plus accumulated interest outstanding.
(2) U.S. dollar-denominated loan at a variable interest rate based on 1-month LIBOR plus i196 bps (i2.11%
at December 31, 2020). At December 31, 2020, $i1 million of accrued interest receivable is included in Due from Unconsolidated Affiliates – Current.
(3)Mexican peso-denominated revolving line of credit for up to i14.2
billion Mexican pesos or approximately $i712 million U.S. dollar-equivalent, at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus i220
bps (i6.66% at December 31, 2020), to finance construction of the natural gas marine pipeline. At December 31, 2020, $i2 million
of accrued interest receivable is included in Due from Unconsolidated Affiliates – Current.
(4) U.S. dollar-denominated loan at a variable interest rate based on 6-month LIBOR plus i290 bps (i3.16%
at December 31, 2020).
(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.
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F-50
The following table summarizes
income statement information from unconsolidated affiliates.
INCOME STATEMENT IMPACT FROM UNCONSOLIDATED AFFILIATES
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 i13 to i20
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 i20-year contract for up to i155 MW of renewable power supplied from the ESJ wind power generation facility. ESJ is a i50%
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 certain business services to Cameron LNG JV. Sempra LNG had an agreement to provide transportation services to Cameron LNG JV for capacity on the Cameron Interstate Pipeline through August 2020, when Cameron LNG JV achieved commercial operations of Train 3 of its Phase 1 project. Sempra Energy has provided guarantees to Cameron LNG JV and to CFIN, 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, 2020, Sempra Energy was in compliance with all covenants related to its debt agreements.
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At
December 31, 2020, 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 $i12.2 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $i12.6
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, $i1.1 billion of Sempra Energy’s consolidated retained earnings represents undistributed earnings of equity method investments at December 31,
2020.
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, 2020, Sempra Energy could have received combined loans and dividends of approximately $i717 million from SDG&E and approximately
$i148 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, 2020 is ii52/%
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 i65%, as we discuss in Note 7.
Based on these restrictions, at December 31, 2020, SDG&E’s restricted net assets were $i7.0
billion and SoCalGas’ restricted net assets were $i5.0 billion, which could not be transferred to Sempra Energy.
Sempra Texas Utilities
Sempra Energy owns an indirect, i100%
interest in Oncor Holdings, which owns an i80.25% 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 ring-fencing measures, governance mechanisms and commitments, Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its independent directors
or a minority member director determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements.
▪Oncor must remain in compliance with its debt-to-equity ratio established by the PUCT for ratemaking purposes and may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause it to exceed its PUCT authorized debt-to-equity ratio. Oncor’s authorized regulatory capital structure is i57.5%
debt to i42.5% equity at December 31, 2020.
▪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, 2020, all of Oncor’s senior secured
ratings were above BBB.
▪Oncor’s revolving credit line and certain of its other debt agreements require it to maintain a consolidated senior debt-to-capitalization ratio of no more than i65% and observe certain affirmative covenants. At December 31, 2020, Oncor was in compliance with these covenants.
Based on these restrictions, at December 31, 2020, Oncor’s restricted net
assets were $i11.9 billion, which could not be transferred to Sempra Energy.
Sempra Energy owns an indirect, i50%
interest in Sharyland Holdings, which owns a i100% interest in Sharyland Utilities. Significant restrictions related to this equity method investment include:
▪Sharyland Utilities may not pay dividends or make other distributions (except for contractual payments) without the consent of the JV partner.
▪Sharyland Utilities must remain in compliance with the capital structure established by the PUCT for ratemaking purposes and
may not pay dividends or other distributions (except for contractual tax payments) if that payment would cause its debt to exceed i55% of its capital structure.
▪Sharyland Utilities has a revolving credit line and a term loan credit agreement that require it to maintain a consolidated debt-to-capitalization ratio of no more than i70%
and observe certain customary reporting requirements and other affirmative covenants. At December 31, 2020, Sharyland Utilities was in compliance with these and all other covenants.
F-52
Based on these restrictions, at December 31, 2020, Sharyland Utilities’ restricted net assets were $i114
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 $i185 million at Sempra Energy’s consolidated Mexican
subsidiaries at December 31, 2020.
▪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 $i12 million are restricted at December 31, 2020.
▪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 $i9 million are restricted at December 31, 2020.
▪ESJ,
a i50% 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 $i7
million are restricted at December 31, 2020.
▪TAG JV, a i50% 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 $i73
million are restricted at December 31, 2020.
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. We discuss Cameron LNG JV’s debt agreements and the associated Sempra Energy guarantees in Note 6. Under these restrictions, net assets of Cameron LNG JV of approximately $i452
million are restricted at December 31, 2020.
OTHER (EXPENSE) INCOME, NET
iOther (Expense) Income, Net on the Consolidated Statements of Operations consists of the following:
Non-service
component of net periodic benefit cost
(i102)
(i132)
(i35)
Fine
related to Energy Efficiency Program Inquiry
(i6)
i—
i—
Penalties
related to billing practices OII
i—
(i8)
i—
Interest
on regulatory balancing accounts, net
i14
i14
i2
Sundry,
net
(i31)
(i7)
(i2)
Total
$
(i48)
$
i77
$
i58
SDG&E:
Allowance
for equity funds used during construction
$
i79
$
i56
$
i61
Non-service
component of net periodic benefit cost
(i20)
(i20)
(i6)
Fine
related to Energy Efficiency Program Inquiry
(i6)
i—
i—
Interest
on regulatory balancing accounts, net
i9
i13
i4
Sundry,
net
(i10)
(i10)
(i3)
Total
$
i52
$
i39
$
i56
SoCalGas:
Allowance
for equity funds used during construction
$
i41
$
i34
$
i36
Non-service
component of net periodic benefit cost
(i54)
(i72)
(i10)
Penalties
related to billing practices OII
i—
(i8)
i—
Interest
on regulatory balancing accounts, net
i5
i1
(i2)
Sundry,
net
(i20)
(i10)
(i9)
Total
$
(i28)
$
(i55)
$
i15
(1)Represents
investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are offset by corresponding changes in compensation expense related to the plans, recorded in O&M on the Consolidated Statements of Operations.
(2) Includes losses of $i42 million in 2020, gains of $i30
million in 2019 and losses of $i3 million in 2018 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. iiNEW 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 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13, as amended by subsequently issued ASUs, changes how entities 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 receivables and 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. We adopted the standard on January 1, 2020 using a modified retrospective approach through a cumulative-effect adjustment to retained earnings. The adoption primarily impacted the expected credit losses associated with accounts receivable balances, amounts due from unconsolidated affiliates and off-balance sheet financial guarantees. There was an insignificant impact to SDG&E’s and SoCalGas’ balance sheets from adoption. iThe
following table shows the initial (decreases) increases on Sempra Energy’s balance sheet at January 1, 2020 from adoption of ASU 2016-13.
F-54
IMPACT FROM ADOPTION OF ASU 2016-13
(Dollars in millions)
Sempra Energy Consolidated
Accounts receivable – trade, net
$
(i1)
Due
from unconsolidated affiliates – noncurrent
(i6)
Deferred income tax assets
i4
Other
current liabilities
i4
Deferred credits and other
i2
Retained
earnings
(i7)
Other noncontrolling interests
(i2)
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. We adopted ASU 2017-04 on January 1, 2020 and are applying the standard on a prospective basis to our goodwill impairment tests.
iASU
2020-04, “Facilitation of the Effects of Reference Rate Reform on Financial Reporting”: ASU 2020-04 provides optional expedients and exceptions for applying U.S. GAAP to contract modifications that replace LIBOR or another reference rate affected by reference rate reform and to hedging relationships that reference LIBOR or another reference rate affected or expected to be affected by reference rate reform. ASU 2020-04 was effective March 12, 2020 and can be applied through December 31, 2022, with certain exceptions for hedging relationships that continue to exist after this date, and may be applied from January 1, 2020. For contract modifications, the standard allows entities to account for modifications as an event that does not require reassessment or remeasurement (i.e., as a continuation
of the existing contract). The standard also allows entities to amend their formal designation and documentation of hedging relationships affected or expected to be affected by reference rate reform, without having to de-designate the hedging relationship. Entities may elect the optional expedients and exceptions on an individual hedging relationship basis and independently from one another. We elected the optional expedients for contract modifications. We elected the cash flow hedging expedients to disregard the potential discontinuation of a reference rate when assessing whether a hedged forecasted interest payment is probable and to disregard certain mismatches between the designated hedging instrument and the hedged item when assessing the hedge effectiveness. We are applying these expedients prospectively from January 1, 2020. Application of these expedients preserves the presentation of derivatives consistent with
the past presentation.
ASU 2020-06, “Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity”: ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. In addition to other changes, this standard amends ASC 470-20, “Debt with Conversion and Other Options,” by removing the accounting models for instruments with beneficial conversion features and cash conversion features. The standard also amends ASC 260, “Earnings Per Share,” as follows:
▪requires an entity to apply the if-converted method when calculating diluted EPS for convertible instruments and no longer use the treasury stock method, which was previously allowed for certain convertible instruments;
▪requires
an entity to include the effect of potential share settlement in the diluted EPS calculation when an instrument may be settled in cash or shares, and no longer allows an entity to rebut the presumption of share settlement if it has a history or policy of cash settlement;
▪requires an entity to include equity-classified convertible preferred stock that contains down-round features whereby, if the down-round feature is triggered, its effect is treated as a dividend and as a reduction of income available to common shareholders in basic EPS;
▪clarifies that the average market price should be used to calculate the diluted EPS denominator when the exercise price or the number of shares that may be issued is variable, except for certain contingently issuable shares; and
▪clarifies
that the weighted-average share count from each quarter should be used when calculating the year-to-date weighted-average share count.
For public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, including interim periods therein, with early adoption permitted for fiscal years beginning after December 15, 2020. An entity can use either a full or modified retrospective approach to adopt ASU 2020-06 and must disclose, in the period of adoption, EPS transition information about the effect of the change on affected per-share amounts. We plan to adopt the standard on January 1, 2022 and are currently evaluating the effect of the standard on our ongoing financial reporting.
F-55
NOTE
3. iREVENUES
i
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.
Our revenues from contracts with customers are primarily related to the transmission, distribution and storage of natural gas and the generation, transmission and distribution of electricity through our regulated utilities. We also provide other midstream and renewable energy-related services. We assess our revenues on a contract-by-contract basis as well as a portfolio basis to determine the nature, amount, timing and uncertainty, if any, of revenues being recognized.
We
generally recognize revenues when performance of the promised commodity service is provided to our customers and we invoice our customers for an amount that reflects the consideration we are entitled to in exchange for those services. We consider the delivery and transmission of natural gas and electricity and providing of natural gas storage services as ongoing and integrated services. Generally, natural gas or electricity services are received and consumed by the customer simultaneously. Our performance obligations related to these services are satisfied over time and represent a series of distinct services that are substantially the same and that have the same pattern of transfer to the customers. We recognize revenue based on units delivered, as the satisfaction of our performance obligations can be directly measured by the amount of natural gas or electricity delivered to the customer. In most cases, the right to consideration from the customer directly corresponds
to the value transferred to the customer and we recognize revenue in the amount that we have the right to invoice.
The payment terms in our customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.
We exclude sales and usage-based taxes from revenues. In addition, 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:
◦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, resulting in a significant portion of earnings being 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
F-57
within the quarter the auction is held. The California Utilities balance costs and revenues associated with the GHG program through regulatory balancing accounts.
In connection with the COVID-19 pandemic, the California Utilities and the CPUC have implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for residential and small business customers, waiving late payment
fees for business customers, and offering flexible payment plans to customers experiencing difficulty paying their electric or gas bills. Additional measures could be mandated or voluntarily implemented in the future. Under the regulatory compact applicable to the California Utilities, including decoupling of rates, recovery of uncollectible expenses, and other recovery mechanisms potentially available, which we discuss in Note 4, the California Utilities have continued to recognize revenues under ASC 606, “Revenue from Contracts with Customers,” in the year ended December 31, 2020.
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 storage facilities. Under these firm agreements, customers pay a monthly fixed reservation
fee based on the storage capacity reserved rather than the actual volumes stored. For the fixed-fee component, revenue is recognized on a straight-line basis over the term of the contract. We bill customers for any capacity used in excess of the contracted capacity and such revenues are recognized in the month of occurrence. We also recognize revenue for interruptible storage services. As we discuss in Note 5, in February 2019, Sempra 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 Mexico and, previously, Sempra Renewables develop, invest in and operate solar and wind facilities that have long-term PPAs to sell the electricity and the related green energy attributes they generate to customers, generally load serving entities, and also for Sempra 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 and delivered. We invoice customers based on the volume of energy delivered at rates pursuant to the PPAs. As we discuss in Note 5, in December 2018, Sempra Renewables completed the sale of its 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.
F-58
Sempra LNG has a contractual agreement to provide scheduling and marketing of renewable power for Sempra Mexico’s ESJ JV. 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.
iFor
contracts greater than one year, at December 31, 2020, 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, 2020.
REMAINING PERFORMANCE OBLIGATIONS(1)
(Dollars in millions)
Sempra
Energy Consolidated
SDG&E
2021
$
i387
$
i4
2022
i406
i4
2023
i407
i4
2024
i348
i4
2025
i351
i4
Thereafter
i4,361
i67
Total
revenues to be recognized
$
i6,260
$
i87
(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.
i
Activities within Sempra Energy’s and SDG&E’s contract liabilities
are presented below. There were no contract liabilities at SDG&E in 2018 or at SoCalGas in 2020, 2019 or 2018.
CONTRACT LIABILITIES
(Dollars in millions)
2020
2019
2018
Sempra
Energy Consolidated:
Contract liabilities at January 1
$
(i163)
$
(i70)
$
i—
Adoption
of ASC 606
i—
i—
(i61)
Revenue
from performance obligations satisfied during reporting period
i4
i2
i7
Payments
received in advance
(i48)
(i95)
(i16)
Contract
liabilities at December 31(1)
$
(i207)
$
(i163)
$
(i70)
SDG&E:
Contract
liabilities at January 1
$
(i91)
$
i—
Revenue
from performance obligations satisfied during reporting period
i4
i1
Payments
received in advance
i—
(i92)
Contract
liabilities at December 31(2)
$
(i87)
$
(i91)
(1)Balances at December 31, 2020 and 2019 include $i52 million and $i4
million, respectively, in Other Current Liabilities and $i155 million and $i159 million, respectively, in Deferred Credits and Other.
/
(2)Balances at December 31, 2020 and 2019 include $i4 million and $i4
million, respectively, in Other Current Liabilities and $i83 million and $i87 million, respectively, in Deferred Credits and Other.
F-59
Receivables
from Revenues from Contracts with Customers
i
The table below shows receivable balances associated with revenues from contracts with customers on the Consolidated Balance Sheets.
RECEIVABLES
FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(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:
▪costs to purchase natural gas and electricity;
▪costs associated with administering public purpose, demand response, and customer energy efficiency programs;
F-60
▪other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and
▪costs
associated with third party liability insurance premiums.
Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded within a subsequent period based on the nature of the balancing account mechanism. In general, the revenue recognition criteria for balanced costs billed to customers are met at the time the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund for programs authorized, including limitations on the total cost of the program, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers.
We
discuss balancing accounts and their effects further in Note 4.
Other Revenues
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 has an agreement to supply LNG to Sempra Mexico’s ECA Regas Facility. 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 LNG also recognizes other revenues from:
▪fees related to contractual counterparty obligations for non-delivery of LNG cargoes, as described above; and
▪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.
F-61
NOTE
4. iREGULATORY MATTERS
REGULATORY ASSETS AND LIABILITIES
ii
We
show the details of regulatory assets and liabilities in the following table and discuss them below.
Deferred
income taxes recoverable (refundable) in rates
i22
(i108)
Pension
and other postretirement benefit plan obligations
i50
i103
Removal
obligations
(i2,121)
(i2,056)
Environmental
costs
i56
i45
Sunrise
Powerlink fire mitigation
i121
i121
Regulatory
balancing accounts(1)(2)
Commodity – electric
i72
i102
Gas
transportation
i35
i22
Safety
and reliability
i67
i77
Public
purpose programs
(i158)
(i124)
2019
GRC retroactive impacts
i56
i111
Other
balancing accounts
i233
i106
Other
regulatory assets (liabilities), net(2)
i72
(i153)
Total
SDG&E
(i1,548)
(i1,746)
SoCalGas:
Deferred
income taxes refundable in rates
(i82)
(i203)
Pension
and other postretirement benefit plan obligations
i417
i400
Employee
benefit costs
i37
i44
Removal
obligations
(i685)
(i728)
Environmental
costs
i36
i40
Regulatory
balancing accounts(1)(2)
Commodity – gas, including transportation
(i56)
(i118)
Safety
and reliability
i335
i295
Public
purpose programs
(i253)
(i273)
2019
GRC retroactive impacts
i202
i400
Other
balancing accounts
(i58)
(i7)
Other
regulatory assets (liabilities), net(2)
i75
(i101)
Total
SoCalGas
(i32)
(i251)
Sempra
Mexico:
Deferred income taxes recoverable in rates
i80
i83
Other
regulatory assets
i—
i6
Total
Sempra Energy Consolidated
$
(i1,500)
$
(i1,908)
(1) At
December 31, 2020 and 2019, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $i139 million and $i108
million, respectively, and for SoCalGas was $i218 million and $i500 million,
respectively.
//
(2) Includes regulatory assets earning a return.
In the table above:
▪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.
▪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
F-62
taxes over the lives of the assets that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities include excess deferred income taxes resulting from statutory income tax rate changes and certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 8.
▪Regulatory assets/liabilities
related to pension and other postretirement benefit plan obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded.
▪The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.
▪Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred (or paid).
▪Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through
rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.
▪The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining i49-year period.
▪Over- and undercollected regulatory balancing accounts reflect the difference between
customer billings and recorded or CPUC-authorized costs, including commodity costs. Depreciation, taxes and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. The adopted revenue requirements in the 2019 GRC FD associated with the period from January 1, 2019 through December 31, 2019 are being recovered in rates over a 24-month period that began in January 2020.
Amortization expense on regulatory assets for the years ended December 31, 2020, 2019 and 2018 was $i9 million,
$i7 million and $i5 million, respectively, at Sempra Energy Consolidated, $i4 million,
$i3 million and $i2 million, respectively, at SDG&E, and $i5 million,
$i4 million and $i3 million, respectively, at SoCalGas.
CALIFORNIA UTILITIES
COVID-19
Pandemic Protections
In March 2020, the CPUC required that all energy companies under its jurisdiction, including the California Utilities, take action to implement several emergency customer protection measures to support California customers in light of the COVID-19 pandemic for up to one year. Currently, the customer protection measures are mandatory for all residential and small business customers. In February 2021, the CPUC extended the customer protection measures through June 2021 and may extend them further. Each of the California Utilities was authorized to track and request recovery of incremental costs associated with complying with residential and small business customer protection measures implemented by the CPUC related to the COVID-19 pandemic, including costs associated with suspending service disconnections and uncollectible expenses that arise from these customers’ failure to pay. The California Utilities
expect to pursue recovery of tracked costs in rates in a future CPUC proceeding, which recovery is not assured.
Disconnection OIR
In June 2020, the CPUC issued a decision to adopt certain customer protections to reduce residential customer disconnections and improve reconnection processes, including, among other things, imposing limitations on service disconnections, elimination of deposit requirements and reconnection fees, establishment of the AMP that provides successfully participating, income-qualified residential customers with relief from outstanding utility bill amounts, and increased outreach and marketing efforts. The decision allows each of the California Utilities to establish a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding
utility bill amounts provided under the AMP.
CPUC 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
In September 2019, the CPUC issued a final decision in the 2019 GRC approving SDG&E’s and SoCalGas’ test year revenues for 2019 and attrition year adjustments for 2020 and 2021, which was effective retroactively to January 1, 2019. This is the first GRC that includes revenues authorized for risk assessment mitigation phase activities.
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The
2019 GRC FD approved a test year 2019 revenue requirement of $i1,990 million for SDG&E’s combined operations ($i1,590 million for its electric
operations and $i400 million for its natural gas operations) and $i2,770 million for SoCalGas.
The
increases include separately authorized components for O&M and capital-related costs, as follows:
AUTHORIZED REVENUE REQUIREMENT INCREASES FOR 2020 AND 2021
(Dollars in millions)
2020 increase from
2019
2021 increase from 2020
Revenue increase
Percent increase
Revenue increase
Percent increase
SDG&E:
O&M
$
i20
i2.64
%
$
i19
i2.47
%
Capital-related
costs
i114
i9.74
i83
i6.47
Total
increase
$
i134
i6.74
$
i102
i4.83
SoCalGas:
O&M
$
i36
i2.64
%
$
i34
i2.40
%
Capital-related
costs
i184
i14.36
i116
i7.93
Total
increase
$
i220
i7.92
$
i150
i5.00
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 California Utilities filed the petition in April 2020 and requested authorization of their post-test year ratemaking mechanism for two additional years. We subsequently requested an updated increase in the revenue requirement for SDG&E and SoCalGas of approximately $i91
million and $i150 million, respectively, for 2022, and $i104 million and $i131
million, respectively, for 2023, reflecting certain adjustments. These amounts include revenues for both O&M and capital cost attrition. In June 2020, the CPUC issued a ruling to further clarify the issues for review in the California Utilities’ petition, which are mainly whether the proposed revenue requirements and mechanisms for the two proposed additional attrition years are just and reasonable. In September 2020, the California Utilities filed a status report to summarize positions on how impacts of the COVID-19 pandemic should be incorporated into the proposed attrition rates. The California Utilities proposed to continue with the adopted attrition mechanism using the second quarter 2020 Global Insight utility cost forecast, which incorporates impacts of the COVID-19 pandemic. Intervenors have proposed other alternatives, including using escalation factors based on the Consumer Price Index. We expect a proposed decision in the first quarter of 2021.
The
2019 GRC FD approved the California Utilities’ 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.
The 2019 GRC FD clarified that differences between incurred and forecasted income tax expense due to forecasting differences are not subject to tracking in the income tax expense memorandum account beginning in 2019. SDG&E and SoCalGas previously recorded regulatory liabilities, inclusive of interest, associated with the 2016 through 2018 tracked forecasting differences of $i86 million
and $i89 million, respectively. In April 2020, the CPUC confirmed treatment of the two-way income tax expense memorandum account for these 2016 through 2018 balances, at which time the California Utilities released these regulatory liability balances to revenues and regulatory interest.
CPUC Cost of Capital
In December 2019, the CPUC approved the cost of capital and rate structures (shown in the table below) for SDG&E
and SoCalGas that became effective on January 1, 2020 and will remain in effect through December 31, 2022. 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 i6.22%, which the CPUC approved in March 2020.
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CPUC
AUTHORIZED COST OF CAPITAL AND RATE STRUCTURE
SDG&E
SoCalGas
Authorized weighting
Return on rate base
Weighted return on rate base
Authorized weighting
Return on rate base
Weighted return on rate base
i45.25
%
i4.59
%
i2.08
%
Long-Term
Debt
i45.60
%
i4.23
%
i1.93
%
i2.75
i6.22
i0.17
Preferred
Equity
i2.40
i6.00
i0.14
i52.00
i10.20
i5.30
Common
Equity
i52.00
i10.05
i5.23
i100.00
%
i7.55
%
i100.00
%
i7.30
%
The
CCM was reauthorized in the 2020 cost of capital proceeding to continue through 2022. SDG&E’s CCM benchmark rate is i4.498%, based on Moody’s Baa- utility bond index, and SoCalGas’ CCM benchmark rate is i4.029%, 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. For the 12 months ended September 2020, the first “CCM Period,” the trigger did not occur for SDG&E or SoCalGas. The next CCM Period is from October 2020 to September 2021. The CCM, if triggered in 2021, would be effective January 1, 2022, and would automatically update the authorized cost of debt based on actual costs and update the authorized ROE upward or downward by one-half of the difference between the CCM benchmark and the applicable 12-month average Moody’s utility bond index.
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 TO4 ROE of i10.05% was the basis of SDG&E’s FERC-related revenue recognition until March 2020, when the FERC approved the settlement terms that SDG&E and all settling parties reached in October 2019 on SDG&E’s TO5 filing. The settlement agreement provided for a ROE of i10.60%,
consisting of a base ROE of i10.10% plus an additional i50 bps for
participation in the California ISO. If the FERC issues an order ruling that California IOUs are no longer eligible for the additional California ISO ROE, SDG&E would refund the additional i50 bps of ROE associated with the California ISO as of the refund effective date (June 1, 2019) in this proceeding. The TO5 term is effective June 1, 2019 and shall remain in effect indefinitely, with parties
having the annual right to terminate the agreement beginning in 2022. In 2020, SDG&E recorded retroactive revenues of $i12 million related to 2019, and additional FERC revenues of $i17 million
to conclude a rate base matter, net of certain refunds to be paid to CPUC-jurisdictional customers.
Energy Efficiency Program Inquiry
In January 2020, the CPUC issued a ruling seeking comments on a report prepared by its consultant regarding SDG&E’s Upstream Lighting Program for the program year 2017. The CPUC subsequently expanded the scope of the comments to cover the program year 2018. The Upstream Lighting Program was one of SDG&E’s Energy Efficiency programs designed to produce energy efficiency savings for which SDG&E could earn a performance-based incentive.
Pursuant to the CPUC ruling, intervenors representing ratepayers have questioned SDG&E’s management of the program and alleged that certain program expenditures did not benefit the purpose of the program. As a result of the inquiry, SDG&E voluntarily expanded
its review to include the program year 2019. Based on this review and discussions with intervenors, SDG&E concluded that some concessions were appropriate, which include refunding certain costs and certain performance-based incentives to customers and incurring a fine. Accordingly, in the year ended December 31, 2020, SDG&E reduced revenues by $ii51/ million
and recorded a fine of $ii6/ million in Other (Expense) Income, Net, on the SDG&E and Sempra Energy Consolidated
Statements of Operations. The after-tax impact for the year ended December 31, 2020 was $ii44/ million.
In October 2020, SDG&E executed a settlement agreement with intervenors consistent with these concessions. We expect CPUC approval of the settlement agreement in 2021.
SOCALGAS
OSCs – Energy Efficiency and Advocacy
In October 2019, the CPUC issued an OSC to determine whether SoCalGas should be sanctioned for violation of certain CPUC code sections and orders. The OSC stemmed from approximately 40 days and $i9,000
of transitional energy efficiency (EE) codes
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and standards advocacy activities undertaken by SoCalGas in 2018, following a CPUC decision disallowing SoCalGas’ future engagement in EE statewide codes and standards advocacy.
In December 2019, the CPUC issued a second OSC to determine whether SoCalGas is entitled to the EE program’s shareholder incentives for codes and standards advocacy in 2016 and 2017, whether its shareholders should bear the costs of those advocacy activities, and to address whether any other remedies are appropriate. The scope of this OSC was later expanded to include EE program years 2014 and 2015, and SoCalGas’ engagement with local governments on proposed reach codes.
Intervenors
in these OSCs have suggested the CPUC order various financial and non-financial penalties. If the CPUC were to assess fines or penalties on SoCalGas associated with these OSCs, they could be material. We expect CPUC decisions on these OSCs in the first half of 2021.
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 $i8
million in penalties, including $i3 million that was paid in July 2019 to California’s general fund and $i5 million to be credited to customers that received delayed bills (greater than i45
days) in the form of a $i100 bill credit.
NOTE 5. iACQUISITIONS, DIVESTITURES AND DISCONTINUED OPERATIONS
iWe 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, STIH acquired an additional indirect, i0.1975% interest in Oncor through its acquisition of a i1%
interest in TTHC from Hunt Strategic Utility Investment, L.L.C. (Hunt), including notes receivable due from TTHC with an aggregate outstanding balance of approximately $i6 million, for a total purchase price of approximately $i23
million in cash, bringing Sempra Energy’s indirect ownership interest in Oncor to approximately i80.45%. TTHC indirectly owns i100%
of TTI, which owns i19.75% of Oncor’s outstanding membership interests. At the acquisition date, we determined the fair value of the notes receivable was $i7
million based on a discounted cash flow model, and attributed $i16 million to the investment in TTHC, which we recorded as an equity method investment.
STIH’s acquisition of the i1%
interest was the subject of a lawsuit filed in the Delaware Court of Chancery by the owners of the remaining i99% ownership interest in TTHC. STIH purchased its i1%
interest in TTHC in February 2020 after the Delaware Court of Chancery decided, among other things, that STIH’s right to purchase the i1% interest was superior to that of the remaining owners of TTHC. The remaining owners appealed that decision and, in May 2020, the Delaware Supreme Court reversed the Delaware Court of Chancery’s ruling and remanded the case back to the Delaware Court of Chancery. In September 2020, the Delaware Court of Chancery
ordered, among other things, the rescission of STIH’s purchase of the i1% interest in TTHC. The parties have complied with the court’s order and Sempra Energy’s indirect ownership in Oncor has returned to i80.25%.
We received a full refund of the purchase price from Hunt in September 2020 and have fully unwound the acquisition.
Oncor Holdings
In March 2018, Sempra Energy completed the acquisition of an indirect, i100% interest in Oncor Holdings, which owned i80.03%
of Oncor, and other EFH assets and liabilities unrelated to Oncor. We paid consideration of $i9.45 billion in cash and an additional $i31
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 i0.22% of the outstanding membership interests in Oncor from Oncor Management Investment LLC for $i26
million in
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cash, bringing Sempra Energy’s indirect ownership in Oncor to i80.25%. TTI continues to own i19.75%
of Oncor’s outstanding membership interest.
Due to ring-fencing measures, existing governance mechanisms and commitments in effect, we do not have the power to direct the significant activities of Oncor Holdings and Oncor. Consequently, we account for our i100% ownership interest in Oncor Holdings as an equity method investment. See Note 6 for additional information about our equity method investment in Oncor Holdings and related
ring-fencing measures.
The total purchase price paid was comprised of the following:
▪$i9,450 million of merger consideration;
▪$i31
million adjustment for dividends and payments pursuant to a tax sharing agreement with Oncor and Oncor Holdings;
▪$i26 million paid in a separate transaction to acquire an additional i0.22%
of the outstanding membership interests in Oncor from Oncor Management Investment LLC; and
▪$i59 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. Other EFH assets and liabilities
unrelated to Oncor that were acquired have been subsumed into our parent organization, Parent and other. iThe following table sets forth the allocation of the total purchase price paid to the identifiable assets acquired and liabilities assumed.
Pension and other postretirement benefit plan obligations
i21
Deferred
credits and other
i58
Total liabilities assumed
i102
Net
assets acquired
$
i9,568
Total purchase price paid
$
i9,568
(1) As
adjusted for post-closing items.
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 i100% of the issued and outstanding shares of InfraREIT and i100%
of the limited partnership units of its subsidiary, InfraREIT Partners, LP. Oncor paid consideration of $i1,275 million, or $i21 per share, plus certain
transaction costs incurred by InfraREIT and its subsidiaries and paid by Oncor on their behalf, including $i40 million for a management agreement termination fee. Oncor received a total of $i1,330
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 acquisition, SDTS accepted and assumed certain assets and liabilities of Sharyland Utilities, LP in exchange for certain SDTS assets. SDTS received real
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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. Immediately prior to the completion of the exchange, SDTS became a wholly owned, indirect subsidiary of InfraREIT Partners, LP.
Sharyland Holdings
In May 2019, Sempra Energy acquired an indirect, i50% interest in Sharyland Holdings for $i95
million (net of $i7 million in post-closing adjustments). In connection with and prior to the consummation of the acquisition, Sharyland Holdings owned i100%
of the membership interests in Sharyland Utilities, LP and Sharyland Utilities, LP converted into a limited liability company, named Sharyland Utilities, L.L.C. We account for our indirect, i50% interest in Sharyland Holdings as an equity method investment.
Sempra South American Utilities
Compańía Transmisora del Norte Grande S.A.
In December 2018, Chilquinta Energía acquired a i100%
interest in Compańía 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 $i226 million and paid $i208
million (net of $i18 million cash acquired) with available cash on hand at our former Sempra South American Utilities segment, which is presented in and was included as part of the sale of discontinued operations.
We accounted for this business combination using the acquisition method of accounting. At the acquisition date, we allocated the $i208
million in cash paid to the identifiable assets acquired ($i231 million) and liabilities assumed ($i43
million) based on their respective fair values, with the excess recognized as goodwill ($i38 million), which are included below in the “Assets Held for Sale in Discontinued Operations” table.
PENDING ACQUISITION
Sempra Mexico
ESJ
In February 2021, IEnova agreed to acquire Saavi Energía’s i50%
interest in ESJ for approximately $i83 million. At December 31, 2020, IEnova owned a i50%
interest in ESJ, which is accounted for as an equity method investment. Upon completion of the acquisition, IEnova will own i100% of ESJ and will consolidate it. ESJ owns a fully operating wind power generation facility with a nameplate capacity of i155
MW that is fully contracted by SDG&E. ESJ is constructing a second wind power generation facility, which we expect will be completed in late 2021 or in the first quarter of 2022 and will have a nameplate capacity of i108 MW. We expect to complete the acquisition in the first half of 2021, subject to various closing conditions, including authorizations from the FERC and COFECE.
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 $i1.5 billion ($i900
million after tax and NCI) in June 2018, which included $i1.3 billion ($i755 million after tax and NCI)
at Sempra LNG, included in Impairment Losses on Sempra Energy’s Consolidated Statements of Operations, and $i200 million ($i145
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 $i1.3 billion recorded at Sempra LNG in June 2018 by $i183
million ($i126 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 $i1.1
billion ($i629 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.
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Sempra
LNG
In February 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, and received cash proceeds of $i322 million, net of transaction costs. In January 2019, Sempra LNG completed the sale of other non-utility assets for $i5
million.
Sempra Renewables
In December 2018, Sempra Renewables completed the sale of the following assets for cash proceeds of $i1.6 billion:
▪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);
▪its
solar and battery storage development projects; and
▪its i50% interest in the Broken Bow 2 wind generation facility.
In 2018, we recognized a pretax gain of $i513
million ($i367 million after tax) in Gain on Sale of Assets on Sempra Energy’s Consolidated Statement of Operations.
i
The
following table summarizes the deconsolidation of these subsidiaries in 2018.
In
April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments for $i569 million, net of transaction costs, and recorded a $i61
million ($i45 million after tax and NCI) gain, which is included in Gain on Sale of Assets on the Sempra Energy 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.
DISCONTINUED
OPERATIONS
In January 2019, our board of directors approved a plan to sell our South American businesses. We present these businesses, which previously constituted the Sempra South American Utilities segment, and certain activities associated with those businesses as discontinued operations.
In April 2020, we completed the sale of our equity interests in our Peruvian businesses, including our i83.6% interest in Luz del Sur and our interest in Tecsur, to an affiliate of China Yangtze
Power International (Hongkong) Co., Limited for cash proceeds of $i3,549 million, net of transaction costs and as adjusted for post-closing adjustments, and recorded a pretax gain of $i2,271 million
($i1,499 million after tax).
In June 2020, we completed the sale of our equity interests in our Chilean businesses, including our i100%
interest in Chilquinta Energía and Tecnored and our i50% interest in Eletrans, to State Grid International Development Limited for cash proceeds of $i2,216 million,
net of transaction costs and as adjusted for post-closing adjustments, and recorded a pretax gain of $i628 million ($i248 million
after tax).
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In the year ended December 31, 2020, the pretax gains from the sales of our South American businesses are included in Gain on Sale of Discontinued Operations in the table below and the after-tax gains are included in Income from Discontinued Operations, Net of Income Tax, on the Sempra Energy Consolidated Statements of Operations.
Summarized results from discontinued operations were as follows:
Income
from discontinued operations, net of income tax
i1,850
i363
i188
Earnings
attributable to noncontrolling interests
(i10)
(i35)
(i32)
Earnings
from discontinued operations attributable to common shares
$
i1,840
$
i328
$
i156
(1) Results
include activity until deconsolidation of our Peruvian businesses on April 24, 2020 and Chilean businesses on June 24, 2020 and post-closing adjustments related to the sales of these businesses.
The following table summarizes the carrying amounts of the major classes of assets and related liabilities classified as held for sale in discontinued operations.
Current portion of long-term debt and finance leases
i85
Other
current liabilities
i106
Current liabilities
$
i444
Long-term
debt and finance leases
$
i702
Deferred income taxes
i284
Other
noncurrent liabilities
i66
Noncurrent liabilities
$
i1,052
(1)Primarily
represents funds held in accordance with Peruvian tax law.
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As a result of the sales of our South American businesses, in 2020, we reclassified $i645 million of cumulative foreign currency translation
losses from AOCI to Gain on Sale of Discontinued Operations, which is included in Income from Discontinued Operations, Net of Income Tax, on the Sempra Energy Consolidated Statements of Operations.
NOTE 6. iINVESTMENTS
IN UNCONSOLIDATED ENTITIES
i
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 Statements of Operations. Our foreign equity method investees are generally corporations whose operations are taxable on a standalone basis in the countries in which they operate, and we recognize our equity in such income or loss net of investee income tax. See Note 8 for information on how equity earnings and losses before income taxes are factored into the calculations of our pretax income or loss and ETR.
i
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 $i2,833 million and $i2,823
million higher than the underlying equity in the net assets of the investee at December 31, 2020 and 2019, respectively, due to $ii2,868/
million of equity method goodwill and $ii69/
million in basis differences in AOCI, offset by $i104 million at December 31, 2020 and $i114
million at December 31, 2019 due to a tax sharing liability to TTI under a tax sharing agreement.
(2) The carrying value of our equity method investment is $i42 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 $i12 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 $i5 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 $i130 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 is $i259
million and $i263 million higher than the underlying equity in the net assets of the investee at December 31, 2020 and 2019, respectively, primarily due to guarantees, which we discuss below, interest capitalized on the investment prior to the JV commencing its planned principal operations in August 2019 and amortization of guarantee fees and capitalized interest thereafter.
At
December 31, 2020 and 2019, our share of the undistributed earnings of equity method investments was $i1.1 billion and $i634
million, respectively, including $i792 million at December 31, 2020 in undistributed earnings from investments for which we have more than 50% equity interests.
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SEMPRA TEXAS UTILITIES
Oncor Holdings
As
we discuss in Note 5, in March 2018, we completed the acquisition of an indirect, i100% interest in Oncor Holdings, which owns an i80.25%
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 i100%
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.
i
We provide summarized income statement and balance sheet information for Oncor Holdings in the following table.
In
2020 and 2019, Sempra Energy contributed $i632 million and $i1,587 million, respectively, to
Oncor Holdings, including $i1,067 million in 2019 to fund Oncor’s May 2019 acquisition of interests in InfraREIT and certain acquisition-related expenses. In 2018, Sempra Energy contributed $i230
million in cash to Oncor Holdings.
Sharyland Holdings
As we discuss in Note 5, in May 2019, we acquired an indirect, i50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities, for $i95
million, net of $i7 million in post-closing adjustments, which we account for as an equity method investment. In 2019, we invested cash of $i3
million in Sharyland Holdings.
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SEMPRA MEXICO
ESJ
As we discuss in Note 5, in February 2021, IEnova agreed to acquire Saavi Energía’s i50% interest in ESJ for approximately $i83
million. At December 31, 2020, IEnova owned a i50% interest in ESJ, which is accounted for as an equity method investment. Upon completion of the acquisition, IEnova will own i100%
of ESJ and will consolidate it. We expect to complete the acquisition in the first half of 2021, subject to various closing conditions, including authorizations from the FERC and COFECE.
IMG JV
IEnova has a i40% 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 i35-year
natural gas transportation service contract with the CFE and commenced commercial operation in September 2019. In 2018, Sempra Mexico invested cash of $i80 million in IMG JV.
SEMPRA LNG
Cameron LNG JV
Cameron LNG JV was formed in October 2014 among Sempra Energy and three project partners, TOTAL SE, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation
and Nippon Yusen Kabushiki Kaisha. We account for our i50.2% investment in Cameron LNG JV under the equity method.
Cameron LNG JV operates a three-train natural gas liquefaction export facility with a nameplate capacity of i13.9
Mtpa of LNG, with an export capacity of i12 Mtpa of LNG, or approximately i1.7 Bcf per day. Cameron LNG JV achieved commercial operations of Train 1, Train 2 and Train 3 under its tolling agreements in August 2019, February 2020 and August
2020, respectively. Prior to commencing full commercial operation, Sempra LNG capitalized interest of $i33 million in 2019 and $i47 million in 2018 related to this equity
method investment. In 2020, 2019 and 2018, Sempra LNG contributed $i54 million, $i77 million
and $i228 million, respectively, to Cameron LNG JV.
Cameron LNG JV Financing
General. In August 2014, Cameron LNG JV entered into finance documents (collectively, Loan Facility Agreements) for senior secured financing in an initial aggregate principal amount of up to $i7.4
billion under three debt facilities provided by the Japan Bank for International Cooperation (JBIC) and 29 international commercial banks, some of which will benefit from insurance coverage provided by Nippon Export and Investment Insurance (NEXI).
The Loan Facility Agreements and related finance documents provide senior secured term loans with a maturity date of July 15, 2030. The proceeds of the loans were used for financing the cost of development and construction of the three-train Cameron LNG project. The Loan Facility Agreements and related finance documents contain customary representations and affirmative and negative covenants for project finance facilities of this kind with the lenders of the type participating in the Cameron LNG JV financing.
In December 2019, Cameron LNG JV refinanced the commercial bank portion of the
Loan Facility Agreements not covered by NEXI with $i3.0 billion of senior secured notes issued in a private placement bond offering. The senior secured notes bear interest at a weighted-average fixed rate of i3.39%
at December 31, 2020 with a weighted-average tenor of i15.4 years.
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 i0.98%
per annum over LIBOR prior to financial completion of the project and i1.22% per annum over LIBOR following financial completion of the project. The original Loan Facility Agreements required Cameron LNG JV to hedge i50%
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 i50%. In November 2014, Cameron LNG JV entered into floating-to-fixed interest rate swaps for approximately $i3.7
billion notional amount, resulting in an effective fixed rate of i3.19% 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 $i1.5
billion notional amount, resulting in an effective fixed rate of i3.32% for the LIBOR component of the interest rate on the loans. In December 2019, approximately $i790 million of the
$i1.5 billion notional amount was terminated as a result of the refinancing, resulting in an effective fixed rate of i3.26% for the LIBOR component of the interest rate on the remaining loans
outstanding.
F-74
The weighted-average all-in cost of the loans outstanding under the original Loan Facility Agreements and the newly issued senior secured notes is i3.72%.
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 i50.2% of Cameron LNG JV’s obligations under the original Loan Facility Agreements and the newly issued senior secured notes, or a maximum amount of $i4.0
billion. Guarantees for the remaining i49.8% 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 liquefaction project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operations and meeting certain operational performance tests that are currently underway. We expect the project to achieve financial completion and the guarantees to be terminated in the first
half of 2021, but this timing could be delayed, perhaps substantially, if these operational performance tests are not completed due to weather-related events, other events or other factors beyond our control. Sempra Energy recorded a liability of $i82 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 $i3
million in December 2019, with an associated carrying value of $i1 million at December 31, 2020, 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 decreasing 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 i37.65% 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 i10% 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 i50.2%
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 that results in failure to achieve financial completion by September 30, 2021 would result in an event of default under Cameron LNG JV’s financing agreements and a potential
demand of up to $i4.0 billion on Sempra Energy’s guarantees. Further, pursuant to the financing agreements, Cameron LNG JV is restricted from making distributions to its project owners, including Sempra LNG, from January 1, 2021 until the earlier of September 30, 2021 and the achievement of financial completion.
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 i50.2%
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 i50.2% share of all then outstanding senior debt obligations within
five business days (other than in the case of a bankruptcy default, which is automatic).
Sempra Energy Support Agreement for CFIN
In July 2020, CFIN entered into a financing arrangement with Cameron LNG JV’s four project owners and received aggregate proceeds of $i1.5 billion from two project owners and from external lenders on behalf of the other two project owners (collectively, the affiliate loans), based on their proportionate ownership interest in Cameron LNG JV.
CFIN used the proceeds from the affiliate loans to provide a loan to Cameron LNG JV. The affiliate loans mature in 2039. Principal and interest will be
F-75
paid from Cameron LNG JV’s project cash flows from its three-train natural gas liquefaction facility. Cameron LNG JV used the proceeds from its loan to return equity to its project owners. Sempra Energy used its $i753
million share of the proceeds for working capital and other general corporate purposes, including the repayment of indebtedness.
Sempra Energy’s $i753 million proportionate share of the affiliate loans, based on its i50.2%
ownership interest in Cameron LNG JV, was funded by external lenders comprised of a syndicate of eight banks (the bank debt) to whom Sempra Energy has provided a guarantee pursuant to a Support Agreement. Under the terms of the Support Agreement, Sempra Energy has severally guaranteed repayment of the bank debt plus accrued and unpaid interest if CFIN fails to pay the external lenders. Additionally, the external lenders may exercise an option to put the bank debt to Sempra Energy on every one-year anniversary of the closing of the affiliate loans, as well as upon the occurrence of certain events, including a failure by CFIN to meet its payment obligations under the bank debt. In addition, some or all of the bank debt will be transferred by each external lender back to Sempra Energy on the five-year anniversary of the affiliate loans, unless the external lenders elect to waive their transfer rights six months prior to the five-year anniversary of the affiliate loans.
Sempra Energy also has a right to call the bank debt back from, or to refinance the bank debt with, the external lenders at any time. The Support Agreement will terminate upon full repayment of the bank debt, including repayment following an event in which the bank debt is put to Sempra Energy. In exchange for this guarantee, the external lenders will pay a guarantee fee that is based on the credit rating of Sempra Energy’s long-term senior unsecured non-credit enhanced debt rating, which guarantee fee Sempra LNG will recognize as interest income as earned. Sempra Energy’s maximum exposure to loss is the bank debt plus any accrued and unpaid interest and related fees, subject to a liability cap of i130%
of the bank debt, or $i979 million. We measure the Support Agreement at fair value, net of related guarantee fees, on a recurring basis (see Note 12). At December 31, 2020, the fair value of the Support Agreement was $i3
million, of which $i7 million is included in Other Current Assets offset by $i4 million included in Deferred Credits
and Other on the Sempra Energy Consolidated Balance Sheet.
SEMPRA RENEWABLES
As a result of the plan of sale, Sempra Renewables recorded an other-than-temporary impairment on certain of its wind equity method investments totaling $i200 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 $i5 million in its unconsolidated JVs.
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 $i65
million in Equity Earnings on Sempra Energy’s Consolidated Statement of Operations. In 2020, we recorded a charge of $i100 million in Equity Earnings on Sempra Energy’s Consolidated Statement of Operations for losses from our investment in RBS Sempra Commodities. We recognized a corresponding liability of $i25
million in Other Current Liabilities and $i75 million in Deferred Credits and Other for our share of estimated losses in excess of the carrying value of our equity method investment. 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.
F-76
SUMMARIZED FINANCIAL INFORMATION – OTHER EQUITY METHOD INVESTMENTS
(1) On
April 22, 2019, Sempra Renewables sold its remaining wind assets and investments. As of April 22, 2019, these wind assets and investments are no longer equity method investments.
(2) On December 13, 2018, Sempra Renewables sold all its operating solar assets, including its solar equity method investments, and its i50%
interest in the Broken Bow 2 wind power generation facility. As of December 13, 2018, the solar equity method investments and Broken Bow 2 are no longer equity method investments.
(3) Except for our investments in Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.
NOTE
7. iDEBT AND CREDIT FACILITIES
LINES OF CREDIT
Primary U.S. Committed Lines of Credit
At December 31, 2020, Sempra Energy Consolidated had an aggregate capacity of $i6.7
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 $i200 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 $i500 million. No letters of credit were outstanding at December 31, 2020.
(3)The facility also provides for issuance of $i100
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 $i250 million. No letters of credit were outstanding at December 31, 2020.
(4)Commercial
paper outstanding is before reductions of a negligible amount of unamortized discount.
/
F-77
The principal terms of the primary U.S. committed lines of credit in the table above include the following:
▪Each is a i5-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 i23 lenders. No single lender has greater than a i6%
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 i65%
at the end of each quarter. At December 31, 2020, 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 committed lines of credit aggregating $i1.8
billion at December 31, 2020. The principal terms of these credit facilities are described below.
(1) iFive-year
revolving credit facility with a syndicate of i10 lenders. Borrowings bear interest at a per annum rate equal to 3-month LIBOR plus i80 bps.
(2) iTwo-year
revolving credit facility with The Bank of Nova Scotia. Borrowings may be made for up to itwo years from September 23, 2019 in U.S. dollars. Borrowings bear interest at a per annum rate equal to 3-month LIBOR plus i54
bps.
In addition to its committed lines of credit, in October 2020, IEnova entered into a ithree-year $i20 million uncommitted
revolving credit facility with Scotiabank Inverlat S.A. (borrowings may be made in either U.S. dollars or Mexican pesos) and a ithree-year $i100 million uncommitted revolving credit facility with The Bank of
Nova Scotia (borrowings may only be made in U.S. dollars). At December 31, 2020, available unused credit on these lines was $i20 million.
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,
2020, we had approximately $i508 million in standby letters of credit outstanding under these agreements.
TERM LOAN
In March 2020 and April 2020, Sempra Energy borrowed a total of $i1,599
million, net of $i1 million of debt discounts and issuance costs, under a 364-day term loan, which had a maturity date of March 16, 2021 with an option to extend the maturity date to September 16, 2021, subject to receiving the consent of the lenders. Sempra Energy used the proceeds from the term loan to repay borrowings on its committed lines of credit and for other general corporate purposes. This term loan was repaid in full in September 2020.
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WEIGHTED-AVERAGE
INTEREST RATES
The weighted-average interest rates on the total short-term debt at December 31, 2020 and 2019 were as follows:
(1) Callable
long-term debt not subject to make-whole provisions.
i
MATURITIES
OF LONG-TERM DEBT(1)
(Dollars in millions)
SDG&E
SoCalGas
Other
Sempra
Energy
Total
Sempra
Energy
Consolidated
2021
$
i585
$
i—
$
i919
$
i1,504
2022
i18
i—
i583
i601
2023
i450
i300
i1,281
i2,031
2024
i—
i500
i564
i1,064
2025
i—
i350
i461
i811
Thereafter
i5,200
i3,609
i7,439
i16,248
Total
$
i6,253
$
i4,759
$
i11,247
$
i22,259
/
(1) Excludes
finance lease obligations, discounts, and debt issuance costs.
F-81
Various long-term obligations totaling $i11.2 billion at Sempra Energy Consolidated at December 31, 2020 are unsecured. This includes unsecured long-term obligations totaling $i200
million at SDG&E and $i309 million at SoCalGas.
Callable Long-Term Debt
i
At the option of Sempra Energy, SDG&E and SoCalGas, certain debt at December 31,
2020 is callable subject to premiums:
CALLABLE LONG-TERM DEBT
(Dollars in millions)
SDG&E
SoCalGas
Other Sempra Energy
Total Sempra Energy Consolidated
Not
subject to make-whole provisions
$
i200
$
i304
$
i1,299
$
i1,803
Subject
to make-whole provisions
i6,053
i4,450
i8,503
i19,006
/
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 $i6.5
billion at SDG&E and $i1.2 billion at SoCalGas at December 31, 2020.
SDG&E
In September 2020, SDG&E issued $i800
million of i1.70% first mortgage bonds maturing in 2030 and received proceeds of $i792 million (net of debt discount, underwriting discounts
and debt issuance costs of $i8 million). SDG&E used a portion of the proceeds from the offering to redeem $i176 million, prior to a scheduled maturity in 2034, and
$i75 million, prior to a scheduled maturity in 2039, of tax-exempt industrial development revenue refunding bonds in December 2020. SDG&E used the remaining proceeds for general corporate purposes, including repayment of commercial paper.
In April 2020, SDG&E issued $i400
million of i3.32% first mortgage bonds maturing in 2050 and received proceeds of $i395 million (net of debt discount, underwriting discounts
and debt issuance costs of $i5 million). SDG&E used $i200 million of the proceeds from the offering to repay line of credit borrowings, and the remaining proceeds
for working capital and other general corporate purposes.
SoCalGas
In January 2020, SoCalGas issued $i650 million of i2.55%
first mortgage bonds maturing in 2030 and received proceeds of $i643 million (net of debt discount, underwriting discounts and debt issuance costs of $i7
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 October 2020, Sempra Energy redeemed $i700 million of floating-rate notes, prior to a scheduled maturity in January 2021, utilizing a portion of the proceeds received from the sales of our South American businesses.
SDG&E
In
March 2020, SDG&E borrowed $i200 million under a 364-day term loan, which has a maturity date of March 18, 2021 with an option to extend the maturity date to September 17, 2021, subject to receiving the consent of the lenders. Borrowings bear interest at benchmark rates plus i80
bps (i0.95% at December 31, 2020). The term loan provides SDG&E with additional liquidity outside of its committed line of credit. SDG&E classified this term loan as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis by issuing long-term debt. At December 31, 2020, this term loan was included in Current Portion of Long-Term Debt and Finance Leases on SDG&E’s and Sempra Energy’s Consolidated
Balance Sheets.
In the first quarter of 2020, SDG&E borrowed $i200 million from its line of credit and classified it as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or
F-82
by issuing
long-term debt. In the second quarter of 2020, SDG&E repaid these borrowings with proceeds from the issuance of first mortgage bonds, which we discuss above.
SoCalGas
In September 2020, SoCalGas issued $i300 million of senior unsecured floating rate notes maturing in 2023 and received proceeds of $i298
million (net of underwriting discounts and debt issuance costs of $i2 million). The notes bear interest at a per annum rate equal to the 3-month LIBOR rate (or, under certain circumstances, a benchmark replacement rate), reset quarterly, plus i35
bps. SoCalGas may, at its option, redeem some or all of the floating rate notes at any time on or after March 14, 2021 at a redemption price equal to i100% of the principal amount of, plus accrued and unpaid interest on, the notes being redeemed. SoCalGas used the proceeds from the offering for general corporate purposes, including repayment of commercial paper.
Sempra Mexico
In September 2020, IEnova offered and sold in a private
placement $i800 million of i4.75% senior unsecured notes maturing in 2051 and received proceeds of $i770
million (net of debt discount, underwriting discounts and debt issuance costs of $i30 million). IEnova used the proceeds from the offering to repay line of credit borrowings and for other general corporate purposes.
In November 2019, IEnova entered into a financing agreement with International Finance Corporation and North American Development Bank to finance and/or refinance the construction of solar generation projects in Mexico. Under this agreement, in April 2020, IEnova borrowed $i100
million from Japan International Cooperation Agency, with loan proceeds of $i98 million (net of debt issuance costs of $i2 million). The loan matures
in November 2034 and bears interest based on 6-month LIBOR plus i150 bps. In April 2020, IEnova entered into a floating-to-fixed interest rate swap, resulting in a fixed rate of i2.38%.
Also under the financing agreement, in June 2020, IEnova borrowed $i241 million from U.S. International Development Finance Corporation, with loan proceeds of $i236
million (net of debt issuance costs of $i5 million). The loan matures in November 2034 and bears interest at a fixed rate of i2.90%.
Sempra
LNG
In December 2020, ECA LNG Phase 1 entered into a ifive-year loan agreement with a syndicate of nine banks for an aggregate principal amount of up to $i1.6 billion,
of which $i17 million was outstanding as of December 31, 2020. Proceeds from the loan are being used to finance the cost of development and construction of a one-train natural gas liquefaction export facility with a name-plate capacity of i3.25
Mtpa and initial offtake capacity of approximately i2.5 Mtpa. The loan matures in December 2025 and bears interest at a weighted-average blended rate of i2.70%
plus a benchmark interest rate per annum equal to (a) the LIBOR for such interest period divided by (b) one minus the Eurodollar Reserve Percentage; provided that in no event shall the benchmark at any time be less than 0% per annum. ECA LNG Phase 1 may elect for each calendar quarter (i) three successive interest periods of one month or (ii) a single interest period of three months. Sempra Energy, IEnova and TOTAL SE have provided guarantees for repayment of the loans plus accrued and unpaid interest based on their proportionate ownership interest in ECA LNG Phase 1 of i41.7%,
i41.7% and i16.6%,
respectively. The effective interest rate of the loan is based on the interest payments made to external lenders and guarantee payments made to TOTAL SE as a guarantor.
As we discuss in “Shareholders’ Equity and Noncontrolling Interests – Other Noncontrolling Interests – Sempra LNG” in Note 14, notes payable totaling $i22 million due October 1, 2026 were converted to equity by the minority
partner in Liberty Gas Storage LLC and are no longer outstanding.
NOTE 8. iINCOME
TAXES
iWe provide our calculations of ETRs in the following table.
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INCOME
TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
Income tax expense (benefit) from continuing operations
$
i249
$
i315
$
(i49)
Income
from continuing operations before income taxes and equity earnings
$
i1,489
$
i1,734
$
i714
Equity
earnings (losses), before income tax(1)
i294
i30
(i236)
Pretax
income
$
i1,783
$
i1,764
$
i478
Effective
income tax rate
i14
%
i18
%
(i10)
%
SDG&E:
Income
tax expense
$
i190
$
i171
$
i173
Income
before income taxes
$
i1,014
$
i945
$
i849
Effective
income tax rate
i19
%
i18
%
i20
%
SoCalGas:
Income
tax expense
$
i96
$
i120
$
i92
Income
before income taxes
$
i601
$
i762
$
i493
Effective
income tax rate
i16
%
i16
%
i19
%
(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 offset 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.
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RECONCILIATION
OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES
Non-U.S.
earnings taxed at rates different from the U.S. statutory income tax rate(1)
i2
i3
i10
State
income taxes, net of federal income tax benefit
i1
i2
(i8)
Impairment
losses
i1
i—
(i32)
Effects
of the TCJA
i—
i—
i9
Unrecognized
income tax benefits
i—
i—
i4
Noncontrolling
interests in tax equity arrangements
i—
i—
i3
Resolution
of prior years’ income tax items
i—
i—
(i1)
Excess
deferred income taxes outside of ratemaking
i—
(i4)
i—
Compensation-related
items
(i1)
i—
i3
Valuation
allowances
(i1)
i—
i—
Allowance
for equity funds used during construction
(i1)
(i1)
(i4)
Amortization
of excess deferred income taxes
(i1)
(i1)
(i4)
Tax
credits
(i1)
(i2)
(i10)
Foreign
exchange and inflation effects(2)
(i3)
i4
i6
Utility
self-developed software expenditures
(i3)
(i2)
(i7)
Utility
repairs expenditures
(i4)
(i3)
(i13)
Other,
net
i1
(i2)
i1
Effective
income tax rate
i14
%
i18
%
(i10)
%
SDG&E:
U.S.
federal statutory income tax rate
i21
%
i21
%
i21
%
State
income taxes, net of federal income tax benefit
i5
i6
i5
Depreciation
i3
i3
i3
Excess
deferred income taxes outside of ratemaking
i—
(i3)
i—
Amortization
of excess deferred income taxes
(i1)
(i1)
(i1)
Allowance
for equity funds used during construction
(i2)
(i1)
(i2)
Repairs
expenditures
(i3)
(i3)
(i3)
Self-developed
software expenditures
(i4)
(i3)
(i2)
Other,
net
i—
(i1)
(i1)
Effective
income tax rate
i19
%
i18
%
i20
%
SoCalGas:
U.S.
federal statutory income tax rate
i21
%
i21
%
i21
%
Depreciation
i5
i4
i7
State
income taxes, net of federal income tax benefit
i2
i4
i2
Nondeductible
expenditures
i2
i—
i—
Unrecognized
income tax benefits
i—
i—
i4
Compensation-related
items
i—
i—
i1
Resolution
of prior years’ income tax items
i—
i—
(i1)
Excess
deferred income taxes outside of ratemaking
i—
(i5)
i—
Allowance
for equity funds used during construction
(i1)
(i1)
(i2)
Amortization
of excess deferred income taxes
(i1)
(i1)
(i2)
Self-developed
software expenditures
(i4)
(i2)
(i3)
Repairs
expenditures
(i7)
(i4)
(i7)
Other,
net
(i1)
i—
(i1)
Effective
income tax rate
i16
%
i16
%
i19
%
(1)Related
to operations in Mexico.
(2)Due to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of appreciation (depreciation) of the Mexican peso. We also recognize gains (losses) in Other Income, 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.
F-85
In January 2019, our board of directors approved a plan to sell our
South American businesses and we completed the sales in the second quarter of 2020, as we discuss in Note 5. Prior to this decision, our repatriation estimate excluded post-2017 earnings and other basis differences related to our South American businesses. Because of our decision to sell our South American businesses, we no longer assert indefinite reinvestment of these basis differences. Accordingly, we recorded the following income tax impacts from changes in outside basis differences in our discontinued operations in South America:
▪$i89
million income tax benefit in 2019 primarily related to outside basis differences existing as of the January 25, 2019 approval of our plan to sell our South American businesses; and
▪$i7 million income tax benefit in 2020 compared to $i51
million income tax expense in 2019 related to changes in outside basis differences from earnings and foreign currency effects since January 25, 2019.
We expect to repatriate approximately $i1.3 billion of foreign undistributed earnings in the foreseeable future, and have accrued $i58
million of U.S. state deferred income tax liability as of December 31, 2020 for repatriations that we expect will begin in 2021 as cash is generated. We repatriated approximately $i4.7 billion, $i254
million and $i338 million to the U.S. in 2020, 2019 and 2018, respectively.
We have not recorded deferred income taxes with respect to remaining basis differences of approximately $i1.1
billion 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, 2020. The remaining basis differences are calculated pursuant to U.S. federal tax law, which may differ from tax law in California and foreign jurisdictions. It is currently not practicable to determine the hypothetical amount of tax that might be payable if the underlying basis differences were realized.
The remeasurement of deferred income tax balances at SDG&E and SoCalGas in December 2017, as a result of the TCJA, resulted in excess deferred income taxes that previously had been collected from ratepayers at the higher rate. In a January 2019 decision, the CPUC directed certain excess deferred income tax balances generated by activities outside of ratemaking be allocated to shareholders rather than
ratepayers. As a result, in 2019, SDG&E and SoCalGas recorded income tax benefits of $i31 million and $i38
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.
i
The table below presents the geographic components of pretax income.
(1) See
the Income Tax Expense (Benefit) and Effective Income Tax Rates table above for the calculation of pretax income.
/
U.S. pretax income was lower in 2018 compared to 2020 and 2019 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).
F-86
i
The
components of income tax expense are as follows.
Differences in financial and tax bases of fixed assets, investments and other assets(1)
$
i4,891
$
i4,052
U.S.
state and non-U.S. withholding tax on repatriation of foreign earnings
i46
i153
Regulatory
balancing accounts
i587
i468
Right-of-use
assets – operating leases
i144
i131
Property
taxes
i51
i44
Other
deferred income tax liabilities
i40
i93
Total
deferred income tax liabilities
i5,759
i4,941
Deferred
income tax assets:
Tax credits
i1,161
i1,136
Net
operating losses
i1,299
i911
Postretirement
benefits
i162
i200
Compensation-related
items
i169
i161
Operating
lease liabilities
i125
i131
Other
deferred income tax assets
i152
i72
Accrued
expenses not yet deductible
i130
i52
Deferred
income tax assets before valuation allowances
i3,198
i2,663
Less:
valuation allowances
i174
i144
Total
deferred income tax assets
i3,024
i2,519
Net
deferred income tax liability(2)
$
i2,735
$
i2,422
(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, 2020 and 2019, includes $i136 million and $i155
million, respectively, recorded as a noncurrent asset and $i2,871 million and $i2,577 million, respectively, recorded as a noncurrent liability on
the Consolidated Balance Sheets.
(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. iThe 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.
Expiration
of statutes of limitations on tax assessments
$
i—
$
i—
$
(i1)
Potential
resolution of audit issues with various U.S. federal, state and local
and non-U.S. taxing authorities
(i8)
(i8)
(i40)
$
(i8)
$
(i8)
$
(i41)
SDG&E:
Potential
resolution of audit issues with various U.S. federal, state and local
taxing authorities
$
(i6)
$
(i6)
$
(i6)
SoCalGas:
Potential
resolution of audit issues with various U.S. federal, state and local
taxing authorities
$
(i2)
$
(i2)
$
(i2)
/
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 negligible amounts and $i1 million for
F-90
interest expense and penalties at December
31, 2020 and 2019, respectively, on the Consolidated Balance Sheets, and recorded $i1 million of interest expense and penalties in 2018 and negligible amounts in each of 2020 and 2019 on the Consolidated Statements of Operations. SDG&E and SoCalGas each accrued negligible amounts for interest expense and penalties at December 31, 2020 and 2019
on the Consolidated Balance Sheets, and recorded negligible amounts of interest expense and penalties in each of 2020, 2019 and 2018 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 2016. We are subject to examination by major state tax jurisdictions for tax years after 2012. Certain major non-U.S. income tax returns for tax years 2013 through the present are open to examination. We are also open to examination for non-U.S. income tax returns related to our prior interest in our commodities business, which we divested in 2010, for years 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 2016 and state tax years after 2012.
In addition, Sempra Energy has filed protests to contest proposed state audit adjustments for tax years 2009 through 2012. The pre-2013 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years.
NOTE
9. iEMPLOYEE BENEFIT PLANS
For our employee benefit plans, we:
▪recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the balance sheet;
▪measure a plan’s assets and
its obligations that determine its funded status as of the end of the fiscal year; and
▪recognize changes in the funded status of pension and PBOP plans in the year in which the changes occur. Generally, those changes are reported in OCI and as a separate component of shareholders’ equity.
The detailed information presented below covers the employee benefit plans of primarily Sempra 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 a member of the Sempra Energy board of directors who was a participant in a predecessor plan on or before June 1, 1998. Pension
benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.
IEnova has an unfunded noncontributory defined benefit plan covering all employees that provides defined benefits to retirees based on date of hire, years of service and final average earnings.
Sempra 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 $i512
million and $i488 million at December 31, 2020 and 2019, respectively.
F-91
PENSION AND OTHER POSTRETIREMENT
BENEFIT PLANS
Benefit Plan Amendments Affecting 2019
In 2019, certain executive participants in a company nonqualified pension plan became eligible in this same plan for Supplemental Executive Retirement Plan benefits. This was treated as a plan amendment and increased the recorded pension liability by $i5 million at Sempra Energy, $i3
million at SDG&E and $i2 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 $i22
million and $i24 million in 2020 and 2019, respectively, and Sempra Energy Consolidated and SDG&E recorded settlement charges of $i12 million
and $i4 million, respectively, in 2018.
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 settlement charges in net periodic benefit cost of $i54 million at Sempra Energy Consolidated, including $i22
million at SDG&E and $i32 million at SoCalGas. The settlement charges were recorded as regulatory assets on the Consolidated Balance Sheets.
Special Termination Benefits Affecting 2018
In 2018, certain nonrepresented 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 that year received an additional
postretirement health benefit in the form of a $i100,000 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 $i5
million for Sempra Energy Consolidated, $i3 million for SDG&E and $i2 million
for SoCalGas in 2018.
Oncor
In 2020 and in each of 2019 and 2018, we had $i11 million and $ii27/
million, respectively, in AOCI representing an actuarial loss related to Oncor’s pension plan.
F-92
Benefit Obligations and Assets
i
The following three tables provide a reconciliation of the
changes in the plans’ projected benefit obligations and the fair value of assets during 2020 and 2019, and a statement of the funded status at December 31, 2020 and 2019:
PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SEMPRA ENERGY
CONSOLIDATED
(Dollars in millions)
Pension benefits
Other postretirement
benefits
2020
2019
2020
2019
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net
obligation at January 1
$
i3,768
$
i3,339
$
i913
$
i868
Service
cost
i129
i110
i18
i17
Interest
cost
i129
i139
i33
i36
Contributions
from plan participants
i—
i—
i22
i21
Actuarial
loss
i351
i445
i79
i45
Plan
amendments
i—
i5
i—
i—
Benefit
payments
(i93)
(i93)
(i74)
(i72)
Settlements
(i207)
(i177)
(i2)
(i2)
Net
obligation at December 31
i4,077
i3,768
i989
i913
CHANGE
IN PLAN ASSETS
Fair value of plan assets at January 1
i2,662
i2,160
i1,281
i1,108
Actual
return on plan assets
i350
i496
i164
i218
Employer
contributions
i290
i276
i8
i8
Contributions
from plan participants
i—
i—
i22
i21
Benefit
payments
(i93)
(i93)
(i74)
(i72)
Settlements
(i207)
(i177)
(i2)
(i2)
Fair
value of plan assets at December 31
i3,002
i2,662
i1,399
i1,281
Funded
status at December 31
$
(i1,075)
$
(i1,106)
$
i410
$
i368
Net
recorded (liability) asset at December 31
$
(i1,075)
$
(i1,106)
$
i410
$
i368
/
F-93
PROJECTED
BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
Pension benefits
Other postretirement benefits
2020
2019
2020
2019
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net
obligation at January 1
$
i895
$
i814
$
i177
$
i170
Service
cost
i31
i30
i4
i4
Interest
cost
i30
i34
i6
i7
Contributions
from plan participants
i—
i—
i8
i7
Actuarial
loss
i37
i61
i17
i7
Plan
amendments
i—
i3
i—
i—
Benefit
payments
(i18)
(i18)
(i20)
(i18)
Settlements
(i52)
(i39)
i—
i—
Transfer
of liability from other plans
(i10)
i10
i1
i—
Net
obligation at December 31
i913
i895
i193
i177
CHANGE
IN PLAN ASSETS
Fair value of plan assets at January 1
i739
i600
i197
i172
Actual
return on plan assets
i94
i135
i26
i36
Employer
contributions
i52
i52
i1
i—
Contributions
from plan participants
i—
i—
i8
i7
Benefit
payments
(i18)
(i18)
(i20)
(i18)
Settlements
(i52)
(i39)
i—
i—
Transfer
of assets from other plans
i4
i9
i1
i—
Fair
value of plan assets at December 31
i819
i739
i213
i197
Funded
status at December 31
$
(i94)
$
(i156)
$
i20
$
i20
Net
recorded (liability) asset at December 31
$
(i94)
$
(i156)
$
i20
$
i20
F-94
PROJECTED
BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
Pension benefits
Other postretirement benefits
(Dollars in millions)
2020
2019
2020
2019
CHANGE
IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1
$
i2,526
$
i2,148
$
i688
$
i646
Service
cost
i86
i68
i14
i12
Interest
cost
i88
i91
i25
i27
Contributions
from plan participants
i—
i—
i14
i13
Actuarial
loss
i282
i345
i57
i39
Plan
amendments
i—
i2
i—
i—
Benefit
payments
(i60)
(i59)
(i49)
(i49)
Settlements
(i105)
(i65)
i—
i—
Transfer
of liability to other plans
i12
(i4)
i—
i—
Net
obligation at December 31
i2,829
i2,526
i749
i688
CHANGE
IN PLAN ASSETS
Fair value of plan assets at January 1
i1,737
i1,385
i1,059
i916
Actual
return on plan assets
i243
i320
i134
i178
Employer
contributions
i152
i152
i1
i1
Contributions
from plan participants
i—
i—
i14
i13
Benefit
payments
(i60)
(i59)
(i49)
(i49)
Settlements
(i105)
(i65)
i—
i—
Transfer
of assets from other plans
i2
i4
i—
i—
Fair
value of plan assets at December 31
i1,969
i1,737
i1,159
i1,059
Funded
status at December 31
$
(i860)
$
(i789)
$
i410
$
i371
Net
recorded (liability) asset at December 31
$
(i860)
$
(i789)
$
i410
$
i371
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 2020, 2019 and 2018, 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 2020 were driven primarily by a decrease in discount rates at Sempra Energy, SDG&E and SoCalGas and a decrease in the lump-sum conversion rate at SoCalGas, along with updated census data at Sempra Energy and SoCalGas. These actuarial losses were offset by actuarial gains at Sempra Energy, 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 2020 were driven primarily by a decrease in discount rates at Sempra Energy, SDG&E and SoCalGas and updated census data at SoCalGas. These actuarial losses were offset by a reduction in the 2021 expected health care costs at SoCalGas.
Net Assets and Liabilities
The assets and liabilities of the pension and PBOP plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for
those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic benefit cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year.
The 10% corridor accounting method is used at Sempra 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
F-95
active
participants. The asset smoothing and 10% corridor accounting methods help mitigate volatility of net periodic benefit costs from year to year.
Defined benefit pension and other postretirement plans with an aggregated overfunded status are recognized as an asset and with an aggregated underfunded status are recognized as a liability; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. 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
▪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.
i
The net (liability)
asset is included in the following categories on the Consolidated Balance Sheets at December 31:
PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS
(Dollars in millions)
Pension benefits
Other
postretirement benefits
2020
2019
2020
2019
Sempra Energy Consolidated:
Noncurrent assets
$
i—
$
i—
$
i430
$
i391
Current
liabilities
(i35)
(i59)
(i1)
(i3)
Noncurrent
liabilities
(i1,040)
(i1,047)
(i19)
(i20)
Net
recorded (liability) asset
$
(i1,075)
$
(i1,106)
$
i410
$
i368
SDG&E:
Noncurrent
assets
$
i—
$
i—
$
i20
$
i20
Current
liabilities
(i2)
(i3)
i—
i—
Noncurrent
liabilities
(i92)
(i153)
i—
i—
Net
recorded (liability) asset
$
(i94)
$
(i156)
$
i20
$
i20
SoCalGas:
Noncurrent
assets
$
i—
$
i—
$
i410
$
i371
Current
liabilities
(i7)
(i4)
i—
i—
Noncurrent
liabilities
(i853)
(i785)
i—
i—
Net
recorded (liability) asset
$
(i860)
$
(i789)
$
i410
$
i371
/
F-96
i
Amounts
recorded in AOCI at December 31, net of income tax effects and amounts recorded as regulatory assets, are as follows:
AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Pension benefits
Other
postretirement benefits
2020
2019
2020
2019
Sempra Energy Consolidated(1):
Net actuarial (loss) gain
$
(i102)
$
(i113)
$
i8
$
i10
Prior
service cost
(i11)
(i14)
i—
i—
Total
$
(i113)
$
(i127)
$
i8
$
i10
SDG&E:
Net
actuarial loss
$
(i8)
$
(i9)
Prior
service cost
(i2)
(i7)
Total
$
(i10)
$
(i16)
SoCalGas:
Net
actuarial loss
$
(i14)
$
(i7)
Prior
service cost
(i4)
(i3)
Total
$
(i18)
$
(i10)
/
(1)Includes
discontinued operations.
Sempra Energy, SDG&E and SoCalGas each have a funded pension plan. iThe following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31:
OBLIGATIONS
OF FUNDED PENSION PLANS
(Dollars in millions)
2020
2019
Sempra Energy Consolidated:
Projected benefit obligation
$
i3,679
$
i3,578
Accumulated
benefit obligation
i3,265
i3,229
Fair
value of plan assets
i2,788
i2,662
SDG&E:
Projected
benefit obligation
$
i887
$
i861
Accumulated
benefit obligation
i834
i818
Fair
value of plan assets
i819
i739
SoCalGas:
Projected
benefit obligation
$
i2,792
$
i2,505
Accumulated
benefit obligation
i2,431
i2,208
Fair
value of plan assets
i1,969
i1,737
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:
OBLIGATIONS OF UNFUNDED PENSION PLANS
(Dollars in millions)
2020
2019
Sempra Energy Consolidated:
Projected
benefit obligation
$
i184
$
i190
Accumulated
benefit obligation
i146
i158
SDG&E:
Projected
benefit obligation
$
i26
$
i34
Accumulated
benefit obligation
i22
i27
SoCalGas:
Projected
benefit obligation
$
i37
$
i21
Accumulated
benefit obligation
i31
i17
F-97
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:
OBLIGATIONS OF FUNDED OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
2020
2019
Sempra
Energy Consolidated:
Accumulated postretirement benefit obligation
$
i33
$
i32
Fair
value of plan assets
i27
i25
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:
OBLIGATIONS OF UNFUNDED OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
2020
2019
Sempra Energy Consolidated:
Accumulated
postretirement benefit obligation
$
i14
$
i16
Net
Periodic Benefit Cost
i
The following tables provide the components of net periodic benefit cost and pretax amounts recognized in OCI for the years ended December 31:
NET
PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
Pension benefits
Other postretirement benefits
2020
2019
2018
2020
2019
2018
NET
PERIODIC BENEFIT COST
Service cost
$
i129
$
i110
$
i124
$
i18
$
i17
$
i21
Interest
cost
i129
i139
i140
i33
i36
i36
Expected
return on assets
(i169)
(i144)
(i157)
(i55)
(i71)
(i70)
Amortization
of:
Prior service cost (credit)
i12
i12
i11
(i2)
i—
i1
Actuarial
loss (gain)
i35
i36
i22
(i10)
(i10)
(i6)
Settlement
charges
i22
i28
i66
i—
i—
i—
Special
termination benefits
i—
i—
i—
i—
i—
i5
Net
periodic benefit cost (credit)
i158
i181
i206
(i16)
(i28)
(i13)
Regulatory
adjustment
i91
i77
(i30)
i16
i29
i17
Total
expense recognized
i249
i258
i176
i—
i1
i4
CHANGES
IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI (1)
Net loss (gain)
i28
i17
i56
i1
(i3)
(i4)
Prior
service cost
i—
i5
i12
i—
i—
i—
Amortization
of actuarial (loss) gain
(i14)
(i13)
(i12)
i—
i—
i—
Amortization
of prior service cost
(i4)
(i3)
(i2)
i—
i—
i—
Settlements
(i22)
(i28)
(i12)
i—
i—
i—
Total
recognized in OCI
(i12)
(i22)
i42
i1
(i3)
(i4)
Total
recognized in net periodic benefit cost and OCI
$
i237
$
i236
$
i218
$
i1
$
(i2)
$
i—
(1) Includes
discontinued operations.
/
F-98
NET
PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
SAN DIEGO GAS & ELECTRIC COMPANY
(Dollars in millions)
Pension benefits
Other postretirement benefits
2020
2019
2018
2020
2019
2018
NET
PERIODIC BENEFIT COST
Service cost
$
i31
$
i30
$
i30
$
i4
$
i4
$
i5
Interest
cost
i30
i34
i35
i6
i7
i7
Expected
return on assets
(i49)
(i38)
(i47)
(i10)
(i11)
(i13)
Amortization
of:
Prior service cost
i2
i3
i2
i—
i2
i3
Actuarial
loss (gain)
i3
i11
i1
(i3)
(i2)
(i3)
Settlement
charges
i—
i—
i26
i—
i—
i—
Special
termination benefits
i—
i—
i—
i—
i—
i3
Net
periodic benefit cost
i17
i40
i47
(i3)
i—
i2
Regulatory
adjustment
i38
i14
(i8)
i3
i—
i—
Total
expense recognized
i55
i54
i39
i—
i—
i2
CHANGES
IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss (gain)
i6
i5
(i1)
i—
i—
i—
Prior
service cost
i—
i2
i8
i—
i—
i—
Transfer
of actuarial loss
(i7)
i—
i—
i—
i—
i—
Transfer
of prior service cost
(i5)
i—
i—
i—
i—
i—
Amortization
of actuarial loss
(i1)
i—
(i1)
i—
i—
i—
Amortization
of prior service cost
(i1)
(i1)
i—
i—
i—
i—
Settlements
i—
i—
(i4)
i—
i—
i—
Total
recognized in OCI
(i8)
i6
i2
i—
i—
i—
Total
recognized in net periodic benefit cost and OCI
$
i47
$
i60
$
i41
$
i—
$
i—
$
i2
NET
PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OCI
SOUTHERN CALIFORNIA GAS COMPANY
(Dollars in millions)
Pension benefits
Other postretirement benefits
2020
2019
2018
2020
2019
2018
NET
PERIODIC BENEFIT COST
Service cost
$
i86
$
i68
$
i81
$
i14
$
i12
$
i15
Interest
cost
i88
i91
i92
i25
i27
i27
Expected
return on assets
(i107)
(i94)
(i98)
(i43)
(i58)
(i56)
Amortization
of:
Prior service cost (credit)
i8
i8
i8
(i2)
(i2)
(i3)
Actuarial
loss (gain)
i26
i16
i13
(i7)
(i8)
(i2)
Settlement
charges
i—
i—
i32
i—
i—
i—
Special
termination benefits
i—
i—
i—
i—
i—
i2
Net
periodic benefit cost (credit)
i101
i89
i128
(i13)
(i29)
(i17)
Regulatory
adjustment
i53
i63
(i22)
i13
i29
i17
Total
expense recognized
i154
i152
i106
i—
i—
i—
CHANGES
IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net loss
i6
i2
i1
i—
i—
i—
Prior
service cost
i—
i3
i—
i—
i—
i—
Transfer
of actuarial loss
i5
(i4)
i—
i—
i—
i—
Transfer
of prior service cost
i3
(i1)
i—
i—
i—
i—
Amortization
of actuarial loss
(i1)
(i1)
i—
i—
i—
i—
Amortization
of prior service cost
(i1)
i—
(i1)
i—
i—
i—
Total
recognized in OCI
i12
(i1)
i—
i—
i—
i—
Total
recognized in net periodic benefit cost and OCI
$
i166
$
i151
$
i106
$
i—
$
i—
$
i—
F-99
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.
i
The
significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:
WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION
AT DECEMBER 31
Pension
benefits
Other postretirement benefits
2020
2019
2020
2019
Sempra Energy Consolidated:
Discount rate
i2.78
%
i3.49
%
i2.88
%
i3.54
%
Interest
crediting rate(1)(2)
i1.62
i2.28
i1.62
i2.28
Rate
of compensation increase
i2.70-i10.00
i2.70-i10.00
i2.70-i10.00
i2.70-i10.00
SDG&E:
Discount
rate
i2.73
%
i3.44
%
i2.85
%
i3.55
%
Interest
crediting rate(1)(2)
i1.62
i2.28
i1.62
i2.28
Rate
of compensation increase
i2.70-i10.00
i2.70-i10.00
i2.70-i10.00
i2.70-i10.00
SoCalGas:
Discount
rate
i2.79
%
i3.50
%
i2.90
%
i3.55
%
Interest
crediting rate(1)(2)
i1.62
i2.28
i1.62
i2.28
Rate
of compensation increase
i2.70-i10.00
i2.70-i10.00
i2.70-i10.00
i2.70-i10.00
(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.
/
F-100
WEIGHTED-AVERAGE
ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST
YEARS ENDED DECEMBER 31
Pension benefits
Other postretirement benefits
2020
2019
2018
2020
2019
2018
Sempra
Energy Consolidated:
Discount rate
i3.49
%
i4.29
%
i3.64
%
i3.54
%
i4.29
%
i3.68
%
Expected
return on plan assets
i7.00
i7.00
i7.00
i4.64
i6.48
i6.49
Interest
crediting rate(1)(2)
i2.28
i3.36
i2.80
i2.28
i3.36
i2.80
Rate
of compensation increase
i2.70-i10.00
i2.00-i10.00
i2.00-i10.00
i2.70-i10.00
i2.00-i10.00
i2.00-i10.00
SDG&E:
Discount
rate
i3.44
%
i4.29
%
i3.64
%
i3.55
%
i4.30
%
i3.65
%
Expected
return on plan assets
i7.00
i7.00
i7.00
i5.51
i6.92
i6.94
Interest
crediting rate(1)(2)
i2.28
i3.36
i2.80
i2.28
i3.36
i2.80
Rate
of compensation increase
i2.70-i10.00
i2.00-i10.00
i2.00-i10.00
i2.70-i10.00
i2.00-i10.00
i2.00-i10.00
SoCalGas:
Discount
rate
i3.50
%
i4.30
%
i3.65
%
i3.55
%
i4.30
%
i3.70
%
Expected
return on plan assets
i7.00
i7.00
i7.00
i4.41
i6.38
i6.38
Interest
crediting rate(1)(2)
i2.28
i3.36
i2.80
i2.28
i3.36
i2.80
Rate
of compensation increase
i2.70-i10.00
i2.00-i10.00
i2.00-i10.00
i2.70-i10.00
i2.00-i10.00
i2.00-i10.00
(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
i
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:
ASSUMED HEALTH CARE COST TREND RATES
AT DECEMBER 31
Other
postretirement benefit plans
Pre-65 retirees
Retirees aged 65 years and older
2020
2019
2018
2020
2019
2018
Health care cost trend rate assumed for next year
i6.00
%
i6.25
%
i6.50
%
i4.75
%
i4.75
%
i4.75
%
Rate
to which the cost trend rate is assumed to decline (the ultimate trend)
i4.75
%
i4.75
%
i4.75
%
i4.50
%
i4.50
%
i4.50
%
Year
the rate reaches the ultimate trend
2025
2025
2025
2022
2022
2022
/i
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:
▪i33%
domestic equity
▪i22% international equity
▪i21%
long credit
▪i10% diversified real assets
▪i7%
return-seeking credit
▪i5% ultra-long duration government securities
▪i2%
other diversifying assets
/
F-101
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 i74% target allocation to return-seeking assets and a i26%
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 i6.75%
expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between i4% and i12%
on return-seeking assets and between i1% and i4%
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 ii38/%
to return-seeking assets and ii62/%
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 i30% to return-seeking assets and i70%
to risk-mitigating assets. SDG&E’s and SoCalGas’ assets held in other Voluntary Employee Beneficiary Association trusts are invested in accordance with a de-risking glidepath that reduces the assets’ exposure to risk as the trusts become better funded. These specific allocations are periodically reviewed to help ensure that plan assets are best positioned to meet plan obligations.
Fair Value of Pension and Other Postretirement Benefit Plan Assets
We classify the investments in Sempra 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
F-102
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.
F-103
SDG&E and SoCalGas each hold a proportionate share of investment assets in the pension master trust at Sempra Energy Consolidated. iThe
fair values of our pension plan assets by asset category are as follows:
FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF PENSION PLANS
Total
investment assets in the fair value hierarchy
$
i1,819
$
i459
i2,278
Accounts
receivable/payable, net
(i38)
Investments measured at NAV:
Common/collective
trusts
i417
Private equity funds
i5
Total
investment assets
$
i2,662
SDG&E’s proportionate share of investment assets
$
i739
SoCalGas’
proportionate share of investment assets
$
i1,737
F-104
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:
FAIR VALUE MEASUREMENTS – INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS
Total
investment assets in the fair value hierarchy
i134
i18
i152
Accounts
receivable/payable, net
(i2)
Investments measured at NAV – Common/collective trusts
i47
Total
investment assets
i197
SoCalGas:
Cash
and cash equivalents
i3
i—
i3
Equity
securities:
Domestic
i78
i—
i78
International
i48
i—
i48
Registered
investment companies
i52
i—
i52
Fixed
income securities:
Domestic government and government agencies
i267
i21
i288
International
government bonds
i1
i10
i11
Domestic
corporate bonds
i—
i309
i309
International
corporate bonds
i—
i40
i40
Registered
investment companies
i—
i75
i75
Derivative
financial instruments
i3
i—
i3
Total
investment assets in the fair value hierarchy
i452
i455
i907
Accounts
receivable/payable, net
(i5)
Investments measured at NAV – Common/collective trusts
i157
Total
investment assets
i1,059
Other Sempra Energy:
Equity
securities:
Domestic
i9
i—
i9
International
i4
i—
i4
Fixed
income securities:
Domestic government and government agencies
i3
i1
i4
Domestic
corporate bonds
i—
i3
i3
International
corporate bonds
i—
i1
i1
Total
investment assets in the fair value hierarchy
i16
i5
i21
Investments
measured at NAV – Common/collective trusts
i4
Total other Sempra Energy investment assets
i25
Total
Sempra Energy Consolidated investment assets in the fair value hierarchy
$
i602
$
i478
Total
Sempra Energy Consolidated investment assets
$
i1,281
F-106
Future
Payments
i
We expect to contribute the following amounts to our pension and PBOP plans in 2021:
EXPECTED
CONTRIBUTIONS
(Dollars in millions)
Sempra Energy Consolidated
SDG&E
SoCalGas
Pension plans
$
i246
$
i53
$
i157
Other
postretirement benefit plans
i5
i1
i1
/
i
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.
EXPECTED BENEFIT PAYMENTS
(Dollars
in millions)
Sempra Energy Consolidated
SDG&E
SoCalGas
Pension benefits
Other postretirement benefits
Pension benefits
Other postretirement benefits
Pension benefits
Other
postretirement benefits
2021
$
i389
$
i47
$
i112
$
i10
$
i226
$
i34
2022
i268
i47
i68
i10
i172
i34
2023
i255
i48
i65
i10
i166
i35
2024
i246
i48
i61
i10
i159
i35
2025
i239
i47
i60
i10
i157
i35
2026-2030
i1,130
i235
i263
i47
i752
i172
/
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.
i
Employer contributions to the savings plans were as follows:
EMPLOYER
CONTRIBUTIONS TO SAVINGS PLANS
(Dollars in millions)
2020
2019
2018
Sempra Energy Consolidated
$
i47
$
i44
$
i43
SDG&E
i16
i15
i15
SoCalGas
i25
i24
i23
/
The
market value of Sempra Energy common stock held by the savings plans was $i1.1 billion and $i1.3
billion at December 31, 2020 and 2019, respectively.
NOTE 10. iSHARE-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:
▪nonqualified stock options
▪incentive stock options
▪restricted stock awards
F-107
▪restricted stock units
▪stock
appreciation rights
▪performance awards
▪stock payments
▪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, 2020, Sempra Energy had the following types of equity awards outstanding:
▪Nonqualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant,
are service-based, become exercisable over a three-year period (for awards granted in 2020 and 2019) or over a four-year period (for awards granted in 2010 or earlier), and expire i10 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.
▪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 (excluding water companies) and the S&P 500 Index. We use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies (excluding water companies) to develop our targets for awards that vest based on EPS growth.
◦For
awards granted during or after 2014, up to an additional i100% of the granted RSUs may be issued if total return to shareholders or EPS growth exceeds target levels.
◦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 i20%
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 i20% for performance in the bottom quartile. However, in no event will more than an additional i100%
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.
▪Other Performance-Based Restricted Stock Units: RSUs were granted in 2015 in connection with the creation of Cameron LNG JV. The 2015 awards vested in 2019 as both of the following were achieved: (a) the Compensation and Talent Committee of Sempra 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.
▪Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest ratably 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 and Talent 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, 2020, ii6,927,284/common
shares were authorized and available for future grants of share-based awards. iOur 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-
F-108
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. iTotal
share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows:
Share-based compensation expense, before income taxes(1)
$
i62
$
i66
$
i76
Income
tax benefit(1)
(i17)
(i18)
(i21)
$
i45
$
i48
$
i55
Capitalized
share-based compensation cost
$
i11
$
i11
$
i10
Excess
income tax deficiency
$
i19
$
i4
$
i15
SDG&E:
Share-based
compensation expense, before income taxes
$
i11
$
i10
$
i12
Income
tax benefit
(i3)
(i3)
(i3)
$
i8
$
i7
$
i9
Capitalized
share-based compensation cost
$
i7
$
i6
$
i6
Excess
income tax deficiency
$
i3
$
i1
$
i3
SoCalGas:
Share-based
compensation expense, before income taxes
$
i14
$
i15
$
i16
Income
tax benefit
(i4)
(i4)
(i5)
$
i10
$
i11
$
i11
Capitalized
share-based compensation cost
$
i4
$
i5
$
i4
Excess
income tax deficiency
$
i3
$
i1
$
i2
(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. In 2020 and 2019, Sempra Energy’s board of directors granted
i154,860 and i261,075
nonqualified stock options, respectively, that are exercisable over a three-year period. There were ino stock options granted in 2018. The weighted-average per-share fair value for options granted was $i19.76
and $i13.20 in 2020 and 2019, respectively. iTo
calculate this fair value, we used the Black-Scholes model with the following weighted-average assumptions:
The
aggregate intrinsic value at December 31, 2020 is the total of the difference between Sempra Energy’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for nonqualified stock options exercised in the last three years was:
▪$i0.4
million in 2020
▪$i4 million in 2019
▪$i9
million in 2018
We expect a negligible amount of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2020 to be recognized over a weighted-average period of i1.3 years. The weighted-average per-share fair value for nonqualified stock options granted in 2019 was $i106.76.
We
received cash of $i0.2 million and $i3 million from stock option exercises during 2020 and 2019, respectively.
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. iBelow are key assumptions for RSUs granted
in the last three years:
(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 i100% of the shares represented by the RSUs may be issued if Sempra Energy exceeds target performance conditions.
/
In
2020, 2019 and 2018, the total fair value of RSU shares vested during the year was $i70 million, $i36
million and $i32 million, respectively.
We expect $i28
million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2020 to be recognized over a weighted-average period of i1.7 years. The weighted-average per-share fair values for performance-based RSUs granted were $i113.54
and $i105.03 in 2019 and 2018, respectively. The weighted-average per-share fair values for service-based RSUs granted were $i112.50
and $i107.60 in 2019 and 2018, respectively.
NOTE
11. iDERIVATIVE FINANCIAL INSTRUMENTS
i
We use derivative instruments primarily to manage exposures
arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that could cause our asset values to fall or our liabilities to increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.
In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded
at fair value and are therefore excluded from the disclosures below.
In all other cases, we record derivatives at fair value on the Consolidated Balance Sheets. We 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 and undesignated derivatives not subject to rate recovery). We classify cash flows from the principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt as financing activities and settlements of other derivative instruments as operating activities on the Consolidated Statements
of Cash Flows.
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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:
▪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.
▪SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.
▪Sempra Mexico
and Sempra LNG may use natural gas and electricity derivatives, as appropriate, in an effort to optimize the earnings of their assets which support the following businesses: LNG, natural gas transportation and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues 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.
▪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.
i
The following table summarizes net energy derivative volumes.
NET
ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
December 31,
Commodity
Unit of measure
2020
2019
Sempra Energy Consolidated:
Natural gas
MMBtu
i5
i32
Electricity
MWh
i1
i2
Congestion
revenue rights
MWh
i43
i48
SDG&E:
Natural
gas
MMBtu
i16
i37
Electricity
MWh
i1
i2
Congestion
revenue rights
MWh
i43
i48
SoCalGas:
Natural
gas
MMBtu
i1
i2
/
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.
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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.
i
The following table presents the net notional amounts of our interest rate derivatives, excluding JVs.
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 utilized foreign currency derivatives to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sales of our operations in Peru and Chile, respectively.
The following table presents the net notional amounts of our foreign currency derivatives, excluding JVs.
The Consolidated Balance Sheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Consolidated Balance Sheets, including the amount of cash collateral receivables that were not offset because the cash collateral was in excess of liability positions.
F-113
i
DERIVATIVE
INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
Additional
cash collateral for commodity contracts
not subject to rate recovery
i43
i—
i—
i—
Additional
cash collateral for commodity contracts
subject to rate recovery
i25
i—
i—
i—
Total(2)
$
i126
$
i85
$
(i53)
$
(i192)
SDG&E:
Derivatives
designated as hedging instruments:
Commodity
contracts subject to rate recovery
i30
i76
(i41)
(i47)
Associated
offsetting commodity contracts
(i4)
(i3)
i4
i3
Associated
offsetting cash collateral
i—
i—
i14
i—
Net
amounts presented on the balance sheet
i26
i73
(i23)
(i44)
Additional
cash collateral for commodity contracts
subject to rate recovery
i16
i—
i—
i—
Total(2)
$
i42
$
i73
$
(i23)
$
(i44)
SoCalGas:
Derivatives
not designated as hedging instruments:
Commodity contracts subject to rate recovery
$
i11
$
i—
$
(i6)
$
i—
Associated
offsetting commodity contracts
(i2)
i—
i2
i—
Net
amounts presented on the balance sheet
i9
i—
(i4)
i—
Additional
cash collateral for commodity contracts
subject to rate recovery
i9
i—
i—
i—
Total
$
i18
$
i—
$
(i4)
$
i—
(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.
F-115
i
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.
CASH
FLOW HEDGE IMPACTS
(Dollars in millions)
Pretax (loss) gain recognized in OCI
Pretax (loss) gain reclassified from AOCI into earnings
(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 $i87
million of losses, 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 $i1 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, 2020 is approximately i14 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 i19
years.
i
The following table summarizes the effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations.
UNDESIGNATED
DERIVATIVE IMPACTS
(Dollars in millions)
Pretax gain (loss) on derivatives recognized in earnings
Years ended December 31,
Location
2020
2019
2018
Sempra Energy Consolidated:
Commodity
contracts not subject
to rate recovery
Revenues: Energy-Related
Businesses
$
i17
$
i12
$
i26
Commodity
contracts subject
to rate recovery
Cost of Natural Gas
(i7)
i3
i5
Commodity
contracts subject
to rate recovery
Cost of Electric Fuel
and Purchased Power
i88
(i140)
i279
Foreign
exchange instruments
Other (Expense) Income, Net
(i56)
i25
i3
Total
$
i42
$
(i100)
$
i313
SDG&E:
Commodity
contracts subject
to rate recovery
Cost of Electric Fuel
and Purchased Power
$
i88
$
(i140)
$
i279
SoCalGas:
Commodity
contracts subject
to rate recovery
Cost of Natural Gas
$
(i7)
$
i3
$
i5
/
F-116
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 liability position at December 31, 2020 and 2019 was $i16
million and $i21 million, respectively. For SoCalGas, the total fair value of this group of derivative instruments in a liability position at December 31, 2020 and 2019 was $i6
million and $i4 million, respectively. At December 31, 2020, if the credit ratings of Sempra Energy or SoCalGas were reduced below investment grade, $i16
million and $i6 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. iFAIR 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, 2020 and 2019. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value
measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair-valued assets and liabilities, and their placement within the fair value hierarchy.
The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 11 under “Financial Statement Presentation.”
The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).
Our financial assets and liabilities that were accounted for at fair value on a recurring basis in the tables below include the following (other
than a $i5 million investment at December 31, 2019 measured at NAV):
▪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).
▪For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market or income approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward
prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below in “Level 3 Information – SDG&E.”
▪Rabbi Trust investments include 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 December 31, 2020, and 2019.
F-117
▪As
we discuss in Note 6, in July 2020, Sempra Energy entered into a Support Agreement for the benefit of CFIN. We measure the Support Agreement, which includes a guarantee obligation, a put option and a call option, net of related guarantee fees, at fair value on a recurring basis. We use a discounted cash flow model to value the Support Agreement, net of related guarantee fees. Because some of the inputs that are significant to the valuation are less observable, the Support Agreement is classified as Level 3, as we describe below in “Level 3 Information – Sempra LNG.”
F-118
i
RECURRING
FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
i46
i11
i—
i57
Municipal
bonds
i—
i282
i—
i282
Other
securities
i—
i226
i—
i226
Total
debt securities
i46
i519
i—
i565
Total
nuclear decommissioning trusts(1)
i549
i525
i—
i1,074
Interest
rate and foreign exchange instruments
i—
i24
i—
i24
Commodity
contracts not subject to rate recovery
i—
i11
i—
i11
Effect
of netting and allocation of collateral(2)
i43
i—
i—
i43
Commodity
contracts subject to rate recovery
i5
i8
i95
i108
Effect
of netting and allocation of collateral(2)
i11
i8
i6
i25
Total
$
i608
$
i576
$
i101
$
i1,285
Liabilities:
Interest
rate and foreign exchange instruments
$
i—
$
i157
$
i—
$
i157
Commodity
contracts not subject to rate recovery
i—
i17
i—
i17
Commodity
contracts subject to rate recovery
i14
i4
i67
i85
Effect
of netting and allocation of collateral(2)
(i14)
i—
i—
(i14)
Total
$
i—
$
i178
$
i67
$
i245
(1) Excludes
cash, cash equivalents and receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies
i46
i11
i—
i57
Municipal
bonds
i—
i282
i—
i282
Other
securities
i—
i226
i—
i226
Total
debt securities
i46
i519
i—
i565
Total
nuclear decommissioning trusts(1)
i549
i525
i—
i1,074
Commodity
contracts subject to rate recovery
i1
i3
i95
i99
Effect
of netting and allocation of collateral(2)
i10
i—
i6
i16
Total
$
i560
$
i528
$
i101
$
i1,189
Liabilities:
Commodity
contracts subject to rate recovery
$
i14
$
i—
$
i67
$
i81
Effect
of netting and allocation of collateral(2)
(i14)
i—
i—
(i14)
Total
$
i—
$
i—
$
i67
$
i67
(1) Excludes
cash, cash equivalents and receivables (payables), net.
(2)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(1) Includes
the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Level 3 Information
SDG&E
i
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.
F-121
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. iFor 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:
CONGESTION
REVENUE RIGHTS AUCTION PRICE INPUTS
Settlement year
Price per MWh
Median price per MWh
2021
$
(i1.81)
to
$
i14.11
$
(i0.12)
2020
(i3.77)
to
i6.03
(i1.58)
2019
(i8.57)
to
i35.21
(i2.94)
The
impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 11.
Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair
value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. The range and weighted-average price of these inputs at December 31 were as follows:
A
significant increase (decrease) in market electricity forward prices would result in a significantly higher (lower) fair value. We summarize long-term, fixed-price electricity position volumes in Note 11.
Realized gains and losses associated with CRRs and long-term, fixed-price electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Because unrealized gains and losses are recorded as regulatory assets and liabilities, they do not affect earnings.
Sempra LNG
The table below sets forth a reconciliation of changes in the fair value of Sempra Energy’s Support Agreement for the benefit of CFIN classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated.
Change in unrealized gains (losses) relating to instruments still held at December 31
$
i3
(1) Net
gains are included in Interest Income and net losses are included in Interest Expense on the Sempra Energy Consolidated Statement of Operations.
(2) Includes $i7 million in Other Current Assets offset by $i4 million
in Deferred Credits and Other on the Sempra Energy Consolidated Balance Sheet.
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The fair value of the Support Agreement, net of related guarantee fees, is based on a discounted cash flow model using a probability of default and survival methodology. Our estimate of fair value considers inputs such as third-party default rates, credit ratings, recovery rates, and risk-adjusted discount rates, which may be readily observable, market corroborated or generally unobservable inputs. Because CFIN’s credit rating and related default and survival rates are unobservable inputs that are significant to the valuation, the Support Agreement, net of related guarantee fees, is classified as Level 3. We assigned CFIN an internally developed
credit rating of A3 and relied on default rate data published by Moody’s to assign a probability of default. A hypothetical change in the credit rating up or down one notch would not result in a significant change in the fair value of the Support Agreement.
Fair Value of Financial Instruments
The fair values of certain of our financial instruments (cash, accounts 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. iThe
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.
Long-term
amounts due from unconsolidated affiliates
$
i742
$
i—
$
i759
$
i—
$
i759
Long-term
amounts due to unconsolidated affiliates
i195
i—
i184
i—
i184
Total
long-term debt(2)
i21,247
i—
i22,638
i26
i22,664
SDG&E:
Total
long-term debt(3)
$
i5,140
$
i—
$
i5,662
$
i—
$
i5,662
SoCalGas:
Total
long-term debt(4)
$
i3,809
$
i—
$
i4,189
$
i—
$
i4,189
(1) Before
allowances for credit losses of $i3 million. Includes $i3 million
of accrued interest receivable in Due From Unconsolidated Affiliate – Current.
(2) Before reductions of unamortized discount and debt issuance costs of $i268 million and $i225
million at December 31, 2020 and 2019, respectively, and excluding finance lease obligations of $i1,330 million and $i1,289
million at December 31, 2020 and 2019, respectively.
(3) Before reductions of unamortized discount and debt issuance costs of $i52 million and $i48
million at December 31, 2020 and 2019, respectively, and excluding finance lease obligations of $i1,276 million and $i1,270
million at December 31, 2020 and 2019, respectively.
(4) Before reductions of unamortized discount and debt issuance costs of $i40 million and $i34
million at December 31, 2020 and 2019, respectively, and excluding finance lease obligations of $i54 million and $i19
million at December 31, 2020 and 2019, respectively.
We provide the fair values for the securities held in the NDT related to SONGS in Note 15.
NON-RECURRING FAIR VALUE MEASURES
Sempra LNG
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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 i90.9%
ownership interest in Bay Gas and other non-utility assets (the non-utility natural gas storage assets). In June 2018, we also owned a i75.4% interest in LA Storage, a salt cavern development project in Cameron Parish in 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 $i1.3 billion ($i755
million after tax and NCI) in Impairment Losses on Sempra Energy’s Consolidated Statement of Operations.
We measured the estimated fair value of $i190 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 for $i332
million, subject to working capital adjustments and $i20 million representing Sempra LNG’s purchase of the i9.1% 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 $i5 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 $i1.3 billion recorded on June 25, 2018 by $i183
million ($i126 million after tax and NCI), resulting in a total impairment of $i1.1
billion ($i629 million after tax and NCI) for the year ended December 31, 2018, based on a fair value of $i337
million for these non-utility natural gas storage assets.
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 $i200
million ($i145 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 $i145
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.
F-124
i
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.
NON-RECURRING
FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(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. iPREFERRED STOCK
Sempra Energy and SDG&E are authorized to issue up to i50 million and i45
million shares of preferred stock, respectively. At December 31, 2020 and 2019, SDG&E had iino/
preferred stock outstanding. The rights, preferences, privileges and restrictions for any new series of preferred stock would be established by each company’s board of directors at the time of issuance. We discuss SoCalGas preferred stock below.
SEMPRA ENERGY MANDATORY CONVERTIBLE PREFERRED STOCK
In January 2018, we issued i17,250,000 shares of our i6%
mandatory convertible preferred stock, series A (series A preferred stock) in a registered public offering at $i100.00 per share (or $i98.20
per share after deducting underwriting discounts), and received net proceeds of $i1.69 billion (net of underwriting discounts and equity issuance costs of $i32 million).
Each share of series A preferred stock had a liquidation value of $i100.00.
In July 2018, we issued i5,750,000
shares of our i6.75% mandatory convertible preferred stock, series B (series B preferred stock) in a registered public offering at $i100.00 per share (or $i98.35
per share after deducting underwriting discounts), and received net proceeds of $i565 million (net of underwriting discounts and equity issuance costs of $i10 million).
Each share of series B preferred stock has a liquidation value of $i100.00.
Mandatory Conversion
Unless earlier converted, each share of the series A preferred stock and series B preferred stock is to 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 such series of preferred
stock is 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. On January 15, 2021, we converted i17,250,000
shares of series A preferred stock into i13,781,025 shares of our common stock based on a conversion rate of i0.7989 shares
of our common stock for each issued and outstanding share of series A preferred stock. As a consequence, no shares of series A preferred stock were outstanding after January 15, 2021 and the i17,250,000 shares that were formerly series A preferred stock have returned to the status of authorized and unissued shares of preferred stock.
F-125
The
terms of our series A preferred stock and series B preferred stock require a notice to holders when the aggregate adjustment to the conversion rates at which shares of series A preferred stock or series B preferred stock are convertible into shares of Sempra Energy common stock is more than 1%. On July 6, 2020, we notified the holders of the series A preferred stock of such an adjustment. These adjustments, which resulted from the incremental impact of our second quarter dividend declared on our common stock and which became effective as of June 25, 2020, the ex-dividend date for such dividend, include adjustments to the minimum and maximum conversion rates and the related initial and threshold appreciation prices.
i
The
following table illustrates the conversion rate per share of our series B preferred stock, subject to certain anti-dilution adjustments.
CONVERSION RATES
Applicable market value per share of our common stock
Conversion rate (number of shares of our common stock to be received upon conversion of each share of series B preferred stock)
Series B preferred stock
Greater
than $i136.50 (which is the threshold appreciation price)
i0.7326 shares
(approximately equal to $i100.00 divided by the threshold appreciation price)
Equal to or less than $i136.50
but greater than or equal to $i113.75
Between i0.7326
and i0.8791 shares, determined by dividing $i100.00 by the applicable market value of our common stock
Less
than $i113.75 (which is the initial price)
i0.8791 shares
(approximately equal to $i100.00 divided by the initial price)
/
Conversion at the Option of the Holder
Generally, and subject to the terms of the respective series of mandatory convertible 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 were (with respect to the series A preferred stock) or are (with respect to the series B preferred stock) entitled to elect to convert each share of their preferred stock into shares of our common stock at the minimum conversion rate. No holders of the series A preferred stock elected such a conversion before the January 15, 2021 mandatory conversion of all then-outstanding shares. If all outstanding series B preferred stock were converted early, we would issue, subject to anti-dilution adjustments, i4.2
million common shares upon such conversion. In addition, if holders of the series B preferred stock elect to convert any shares during a specified period beginning on the effective date of a fundamental change, as defined in the certificate of determination of preferences of the series B 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 mandatory convertible preferred stock are (or, with respect to the series A preferred stock, were) payable quarterly on a cumulative basis when, as and if declared by our board of directors. All dividends ceased to accrue on the series A preferred stock upon their mandatory conversion on January
15, 2021. We may pay quarterly declared dividends on the series B preferred stock 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 i97% of the volume-weighted average price per share over the ifive-consecutive
trading day period beginning on, and including the sixth trading day prior to, the applicable dividend payment date.
Voting Rights
The holders of the series B preferred stock do not have voting rights, except with respect to any authorization, creation or increase in the authorized amount of any class or series of capital stock ranking senior to the series B preferred stock, certain amendments to the terms of the series B preferred stock, in certain other limited circumstances and as otherwise specifically required by California law. In addition, whenever dividends on any shares of series B preferred stock have not been declared and paid or have been declared but not paid 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 itwo
and the holders of the series B 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 itwo directors who satisfy certain requirements to fill such newly created directorships. This voting right will terminate when all accumulated and unpaid dividends on the series B preferred stock have been paid in full and, upon such termination and the
termination of the same voting rights of all other holders of outstanding series of preferred stock that have such voting rights, the term of office of each director elected pursuant to such rights will terminate and the authorized number of directors will automatically decrease by itwo, subject to the revesting of that right in the event of each subsequent nonpayment.
F-126
Ranking
The
series B preferred stock ranks, with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:
▪senior to our common stock and each other class or series of our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;
▪on parity with our outstanding series C preferred stock and each class or series of our capital stock established in the future if the terms of such capital stock provide that it ranks on parity with the series B preferred stock;
▪junior to each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks senior to the series B preferred stock;
▪junior
to our existing and future indebtedness and other liabilities; and
▪structurally subordinated to all existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.
SEMPRA ENERGY SERIES C PREFERRED STOCK
In June 2020, we issued i900,000 shares of our i4.875%
fixed-rate reset cumulative redeemable perpetual preferred stock, series C (series C preferred stock) in a registered public offering at a price to the public of $i1,000 per share and received net proceeds of $i889 million
after deducting the underwriting discount and equity issuance costs of $i11 million. We used the net proceeds for working capital and other general corporate purposes, including the repayment of indebtedness.
Liquidation Preference
Each share of series C preferred stock has a liquidation preference of $i1,000
plus any accumulated and unpaid dividends (whether or not declared) on such share.
Redemption at the Option of Sempra Energy
The shares of series C preferred stock are perpetual and have no maturity date. However, we may, at our option, redeem the series C preferred stock in whole or in part, from time to time, on any day during the period from and including the July 15 immediately preceding October 15, 2025 and October 15 of every fifth year after 2025 through and including such October 15 at a redemption price in cash equal to $i1,000
per share. Additionally, in the event that a credit rating agency then publishing a rating for us makes certain amendments, clarifications or changes to the criteria it uses to assign equity credit to securities such as the series C preferred stock (Ratings Event), we may redeem the series C preferred stock, in whole but not in part, at any time within 120 days after the conclusion of any review or appeal process instituted by us following the occurrence of the Ratings Event or, if no such review or appeal process is available or sought, the occurrence of such Ratings Event, at a redemption price in cash equal to $i1,020
per share (i102% of the liquidation preference per share).
Dividends
Dividends on the series C preferred stock, when, as and if declared by our board of directors or an authorized committee thereof, are payable in cash, on a cumulative basis, semi-annually in arrears beginning on October 15, 2020. Dividends on the series C preferred stock will be cumulative whether or not:
▪we
have earnings;
▪the payment of such dividends is then permitted under California law;
▪such dividends are authorized or declared; and
▪any agreements to which we are a party prohibit the current payment of dividends, including any agreement relating to our indebtedness.
We accrue dividends on the series C preferred stock on a monthly basis. The dividend rate from and including June 19, 2020 to, but excluding, October 15, 2025 is i4.875%
per annum of the $i1,000 liquidation preference per share. The dividend rate will reset on October 15, 2025 and on October 15 of every fifth year after 2025 and, for each five-year period following such reset dates, will be a per annum rate equal to the Five-year U.S. Treasury Rate (as defined in the certificate of determination of preferences of the series C preferred stock) as of the second business day prior to such reset date, plus a spread of i4.550%,
of the $i1,000 liquidation preference per share.
F-127
Voting Rights
The holders of series C preferred stock do not have any voting rights, except with respect to any authorization, creation or increase in the authorized amount of any class or series of capital stock ranking senior to the series
C preferred stock, certain amendments to the terms of the series C preferred stock, in certain other limited circumstances and as otherwise specifically required by California law. In addition, whenever dividends on any shares of series C preferred stock have not been declared and paid or have been declared but not paid for three or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the series C preferred stock, voting together as a single class with holders of any and all other outstanding series of preferred stock of equal rank having similar voting rights, will be entitled to elect two directors who satisfy certain requirements to fill such two newly created directorships. This voting right will terminate when all accumulated and unpaid dividends on the series C preferred stock have been paid in full and, upon such termination and the termination
of the same voting rights of all other holders of outstanding series of preferred stock that have such voting rights, the term of office of each director elected pursuant to such rights will terminate and the authorized number of directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.
Ranking
The series C preferred stock ranks, with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:
▪senior to our common stock and each other class or series of our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;
▪on parity with our formerly outstanding series A preferred
stock and currently outstanding series B preferred stock and each class or series of our capital stock established in the future if the terms of such capital stock provide that it ranks on parity with the series C preferred stock;
▪junior to each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks senior to the series C preferred stock;
▪junior to our existing and future indebtedness and other liabilities; and
▪structurally subordinated to all existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.
SOCALGAS PREFERRED STOCK
SoCalGas
is authorized to issue up to an aggregate of i11 million shares of preferred stock, series preferred stock and preference stock. iThe table below presents preferred
stock outstanding at SoCalGas:
Less:
i50,970 shares of the 6% Series outstanding owned by PE
(i2)
(i2)
Sempra
Energy - Total preferred stock of subsidiary
$
i20
$
i20
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 $i25 per share plus any unpaid dividends.
In addition to the outstanding preferred stock above, SoCalGas’ articles of incorporation authorize i5
million shares of series preferred stock and i5 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.
F-128
NOTE
14. iSEMPRA ENERGY – SHAREHOLDERS’ EQUITY AND EARNINGS PER COMMON SHARE
SEMPRA ENERGY COMMON STOCK REPURCHASES
On September 11, 2007, our board of directors authorized the repurchase of shares of our common stock, provided that the amounts spent for such purpose do not exceed the greater of $i2 billion
or amounts spent to purchase no more than i40 million shares. On July 1, 2020, we entered into an ASR program under which we prepaid $i500 million
to repurchase shares of our common stock in a share forward transaction. The total number of shares purchased was determined by dividing the $i500 million purchase price by the arithmetic average of the volume-weighted average trading prices of shares of our common stock during the valuation period of July 2, 2020 through August 4, 2020, minus a fixed discount. The program was completed on August
4, 2020 with an aggregate of i4,089,375 shares of Sempra Energy common stock repurchased at an average price of $i122.27 per share. Following
the completion of the ASR program, the aggregate dollar amount authorized by the September 11, 2007 share repurchase authorization was exhausted.
On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $i2 billion or amounts spent to purchase no more than i25 million
shares. No shares have been repurchased under this authorization.
SEMPRA ENERGY COMMON STOCK OFFERINGS
In January 2018, we completed the offering of i26,869,158 shares of our common stock, no par value, in a registered public offering at $i107.00
per share (approximately $i105.07 per share after deducting underwriting discounts), with i23,364,486 shares pursuant
to forward sale agreements. We received net proceeds totaling approximately $i2.8 billion to fully settle these shares, as follows:
▪$i367
million (net of underwriting discounts and equity issuance costs of $i8 million) to cover overallotment shares of i3,504,672
in the first quarter of 2018 at a settlement price of $i105.07 per share;
▪$i900
million (net of underwriting discounts of $i16 million) from the settlement of i8,556,630 shares in the first quarter
of 2018 at a forward sale price of $i105.18 per share;
▪$i800
million (net of underwriting discounts of $i14 million) from the settlement of i7,651,671 shares in the second quarter
of 2018 at forward sale prices ranging from $i104.53 to $i104.58 per share; and
▪$i728
million (net of underwriting discounts of $i13 million) from the settlement of i7,156,185 shares in the third quarter
of 2019 at a forward sale price of $i101.74 per share.
In July 2018, we completed the offering of i11,212,500
shares of our common stock, no par value, in a registered public offering at $i113.75 per share (approximately $i111.87 per share after deducting underwriting discounts), with i9,750,000
shares pursuant to forward sale agreements. We received net proceeds totaling approximately $i1.2 billion to fully settle these shares, as follows:
▪$i164
million (net of underwriting discounts and equity issuance costs of $i3 million) to cover overallotment shares of i1,462,500
in the third quarter of 2018 at a settlement price of $i111.87 per share; and
▪$i1,066
million (net of underwriting discounts of $i18 million) from the settlement of i9,750,000 shares in the fourth quarter
of 2019 at a forward sale price of $i109.33 per share.
F-129
EARNINGS PER COMMON SHARE
iBasic
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.
i
EARNINGS
PER COMMON SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
Income from continuing operations, net of income tax
$
i2,255
$
i1,999
$
i938
Earnings
attributable to noncontrolling interests
(i162)
(i129)
(i44)
Preferred
dividends
(i168)
(i142)
(i125)
Preferred
dividends of subsidiary
(i1)
(i1)
(i1)
Earnings
from continuing operations attributable to common shares
$
i1,924
$
i1,727
$
i768
Numerator
for discontinued operations:
Income from discontinued operations, net of income tax
$
i1,850
$
i363
$
i188
Earnings
attributable to noncontrolling interests
(i10)
(i35)
(i32)
Earnings
from discontinued operations attributable to common shares
$
i1,840
$
i328
$
i156
Numerator
for earnings:
Earnings attributable to common shares
$
ii3,764/
$
ii2,055/
$
ii924/
Denominator:
Weighted-average
common shares outstanding for basic EPS(1)
i291,077
i277,904
i268,072
Dilutive
effect of stock options and RSUs(2)
i1,175
i1,585
i919
Dilutive
effect of common shares sold forward
i—
i2,544
i861
Weighted-average
common shares outstanding for diluted EPS
i292,252
i282,033
i269,852
Basic
EPS:
Earnings from continuing operations
$
i6.61
$
i6.22
$
i2.86
Earnings
from discontinued operations
$
i6.32
$
i1.18
$
i0.59
Earnings
$
i12.93
$
i7.40
$
i3.45
Diluted
EPS:
Earnings from continuing operations
$
i6.58
$
i6.13
$
i2.84
Earnings
from discontinued operations
$
i6.30
$
i1.16
$
i0.58
Earnings
$
i12.88
$
i7.29
$
i3.42
(1)
Includes fully vested RSUs held in our Deferred Compensation Plan of i537 in 2020, i617 in 2019 and i641
in 2018. 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 for 2020, 2019 and 2018 excludes potentially dilutive shares of i187,028, i80,281
and i20,814, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future.
The potentially dilutive impact from the forward sale of our common stock pursuant to the forward sale agreements that we discuss above is reflected in our diluted EPS calculation using the treasury stock method. We have fully settled all forward sale agreements
and those shares are included in weighted-average common shares outstanding for basic EPS.
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The potentially dilutive impact from our mandatory convertible preferred stock is calculated under the if-converted method. The computation of diluted EPS for the years ended December 31, 2020, 2019 and 2018 excludes i17,889,365,
i17,471,375 and i17,197,035
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 and conversion of the series A preferred stock to Sempra Energy common stock on January 15, 2021 in Note 13.
We are authorized to issue i750 million shares of ino
par value common stock. iThe following table provides common stock activity for the last three years.
Issuance
of RSUs held in our Deferred Compensation Plan
i103,552
i59,470
i3,357
Shares
repurchased(3)
(i4,491,858)
(i212,822)
(i200,475)
Common
shares outstanding, December 31
i288,470,244
i291,712,925
i273,769,513
(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. In 2020, shares repurchased includes shares repurchased under the ASR program that we discuss above.
NOTE
15. SAN ONOFRE NUCLEAR GENERATING STATION
SDG&E has a i20% 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.
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 July 2018, the CPUC approved a settlement agreement and, in August 2018, SDG&E, Edison, Cal PA, TURN and other intervenors submitted a notice that they accepted the
settlement agreement, which provided for various disallowances, refunds and rate recoveries.
In connection with the settlement agreement, and in exchange for the release of certain SONGS-related claims, in January 2018, SDG&E and Edison entered into a utility shareholder agreement, which became effective upon CPUC approval of the settlement agreement in July 2018, 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 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. Edison’s payment obligation commenced in October 2018, and amounts are due to SDG&E quarterly thereafter until April 2022. At December 31,
2020, SDG&E has a receivable from Edison, including accrued interest, totaling $i49 million, with $i37 million classified as current and $i12
million classified as noncurrent. This receivable reflects amounts Edison is
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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 work to take i10
years after receipt of all the required permits. The coastal development permit, the last permit required to be obtained, 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 seeking to invalidate this permit and to obtain injunctive relief to stop decommissioning work. In September 2020, the Samuel Lawrence Foundation filed another writ petition under the California Coastal Act in LA Superior Court seeking to set aside the CCC’s July 2020 approval of the inspection and maintenance plan for the SONGS’ canisters and to obtain injunctive relief to stop decommissioning work. Major decommissioning work began in 2020 and has not been interrupted by the writ petitions filed by the Samuel Lawrence Foundation. 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 i20% of the total decommissioning costs.
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. In December 2020, SDG&E received authorization from the CPUC to access NDT funds of up to $i89 million
for forecasted 2021 costs.
In September 2020, the IRS and the U.S. Department of the Treasury published final regulations that clarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified trust fund. The final regulations adopted most of the provisions of the proposed regulations issued in December 2016. The final regulations apply to taxable years ending on or after September 4, 2020 and confirm that the definition of “nuclear decommissioning costs” includes amounts related to the storage of spent nuclear fuel at both on-site and off-site ISFSIs.
The final regulations also clarify that costs incurred for ISFSIs that may be or are expected to be reimbursed by the DOE may be paid or reimbursed from a qualified trust fund. Accordingly, the final regulations
allow SDG&E the option to access qualified trust funds to recover spent fuel storage costs before Edison reaches final settlement with the DOE regarding the DOE’s reimbursement of these costs. Historically, the DOE’s reimbursements of spent fuel storage costs have not resulted in timely or complete recovery of these costs. We discuss the DOE’s responsibility for spent nuclear fuel below.
Nuclear Decommissioning Trusts
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i
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.
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 $i579 million at December 31,
2020. 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 2020 dollars is approximately $i860 million. We expect SDG&E’s undiscounted SONGS
decommissioning payments to be $i110 million in 2021, $i83
million in 2022, $i63 million in 2023, $i45 million
in 2024, $i44 million in 2025, and $i697
million thereafter.
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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. In October 2015, the CCC approved Edison’s application to expand the ISFSI. 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 and was completed in August 2020. 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 $i450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides an additional $i110
million of coverage. If a nuclear liability loss occurs at SONGS and exceeds the $i450 million insurance limit, this additional coverage would be available to provide a total of $i560
million in coverage limits per incident.
As a result of updated coverage assessments, the SONGS owners have nuclear property damage insurance of $i130 million, which exceeds the minimum federal requirements of $i50
million. This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $i3.5 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 $i3.24 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. iCOMMITMENTS 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, 2020, loss contingency accruals for legal matters, including associated legal fees and regulatory matters related to the Leak, that are probable and estimable were $i616 million for Sempra Energy Consolidated
and $i471 million for SoCalGas. Amounts for Sempra Energy Consolidated and SoCalGas include $i445 million for matters related
to the Leak, which we discuss below. We discuss our policy regarding accrual of legal fees in Note 1.
SoCalGas
Aliso Canyon Natural Gas Storage Facility Gas Leak
From October 23, 2015 through February 11, 2016, SoCalGas experienced a natural gas leak from one of the injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility in Los Angeles County. As described below in “Civil and Criminal Litigation” and “Regulatory Proceedings,” numerous lawsuits, investigations and regulatory proceedings have been
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initiated
in response to the Leak, resulting in significant costs, which together with other Leak-related costs are discussed below in “Cost Estimates, Accounting Impact and Insurance.”
Civil and Criminal Litigation. As of February 22, 2021, i395 lawsuits, including approximately i36,000
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
and 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 initial trial previously scheduled for June 2020 for a small number of randomly selected individual plaintiffs was postponed, with a new trial date yet to be determined by the court.
In January 2017, itwo
consolidated class action complaints were filed against SoCalGas and Sempra Energy, ione on behalf of a putative class of persons and businesses who own or lease real property within a five-mile radius of the well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). The Property Class Action asserts claims for strict liability for ultra-hazardous activities, negligence, negligence per se, violation of the California
Unfair Competition Law, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action asserts a claim for violation of the California Unfair Competition Law. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees.
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 i51
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.
iFour
shareholder derivative actions were filed alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas. iThree of the actions were joined in an Amended Consolidated Shareholder Derivative Complaint, which was dismissed with prejudice in January 2021. The remaining action was also dismissed but plaintiffs were given leave to amend their complaint.
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.
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 of three actions filed by these entities under which SoCalGas made payments and agreed to provide funding for environmental projects totaling $i120
million, including $i21 million in civil penalties, as well as other safety-related commitments.
In September 2016, SoCalGas settled a misdemeanor criminal complaint filed in February 2016 by the Los Angeles County District Attorney’s Office against SoCalGas, pleading no contest to a charge that it failed 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). In November 2016, the LA Superior Court approved the settlement and entered judgment on the notice charge. Under the settlement, SoCalGas paid a $i75,000 fine, $i233,500
in penalties, and $i246,673 to reimburse costs incurred by Los Angeles County Fire Department’s Health and Hazardous Materials Division, as well as completed operational commitments estimated to cost approximately $i6
million. 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
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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. Following the hearing, the trial court denied restitution. In December 2020, the California Supreme Court denied review of the ruling.
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 California Public Utilities Code Section 451 or other laws, CPUC orders or decisions, rules or requirements, whether SoCalGas engaged in unreasonable and/or imprudent practices with respect to its operation and maintenance of the Aliso Canyon natural gas storage facility or its related record-keeping practices, whether SoCalGas cooperated sufficiently with the SED 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, the SED, based largely on the Blade report, alleged a total of i330
violations, asserting that SoCalGas violated California Public Utilities Code Section 451 and failed to cooperate in the investigation and to keep proper records. Hearings on a subset of issues are scheduled to begin in March 2021. The second phase will consider whether SoCalGas should be sanctioned for the Leak and what damages, fines or other penalties or sanctions, if any, should be imposed for any violations, unreasonable or imprudent practices, or failure to sufficiently cooperate with the SED as determined by the CPUC in the first phase. In addition, the second phase will determine the amounts of various costs incurred by SoCalGas and other parties in connection with the Leak and the ratemaking treatment or other disposition of such costs, which could result in little or no recovery of such costs by SoCalGas. SoCalGas has engaged in settlement discussions with the SED in connection with this proceeding.
In February 2017,
the CPUC opened a proceeding pursuant to SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, but excluding issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The CPUC issued a decision on the interim range of gas inventory levels at the Aliso Canyon natural gas storage facility in November 2020 with a final determination to be made within the SB 380 OII proceeding. The first phase of the proceeding established a framework for the hydraulic, production cost and economic modeling assumptions for the potential reduction in usage or elimination of the Aliso Canyon natural gas storage facility. Phase 2 of the proceeding, which 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. In December 2019, the CPUC added a third phase of the proceeding and engaged a consultant to consider alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated in either the 2027 or 2045 timeframe, which is currently underway.
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, 2020, the Aliso Canyon natural gas storage facility had a net book value of $i821
million. Any significant impairment of this asset, or higher operating costs and additional capital expenditures incurred by SoCalGas that 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, Accounting Impact and Insurance. 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, 2020, SoCalGas estimates its costs related to the Leak are $i1,627 million (the cost estimate), which includes $i1,279
million of costs recovered or probable of recovery from insurance. This cost estimate may increase significantly as more information becomes available. A substantial portion of the cost estimate has been paid, and $i451 million is accrued as Reserve for Aliso Canyon Costs as of December 31, 2020 on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets.
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In
2020, SoCalGas recorded $i484 million in costs, inclusive of estimated legal costs, related to settlement discussions in connection with civil litigation and regulatory matters described above in “Civil and Criminal Litigation” and “Regulatory Proceedings.” Of this amount, $i177
million was recorded in Insurance Receivable for Aliso Canyon Costs on the SoCalGas and Sempra Energy Consolidated Balance Sheets and $i307 million ($i233
million after tax) was recorded in Aliso Canyon Litigation and Regulatory Matters on the SoCalGas and Sempra Energy Consolidated Statements of Operations. These accruals are included in the cost estimate that we describe above.
Except for the amounts paid or estimated to settle certain actions, as described in “Civil and Criminal Litigation” and “Regulatory Proceedings” above, the cost estimate does not include litigation, regulatory proceedings or regulatory costs to the extent it is not possible to predict at this time 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. 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. These costs not included in the cost estimate could be significant and could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
We have received insurance payments for many of the costs included in the cost estimate, including temporary relocation and associated processing costs, control-of-well expenses, costs of the government-ordered response to the Leak, certain legal costs and lost gas. As of December 31, 2020, we recorded the expected recovery of the cost estimate related to the Leak of $i445
million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Consolidated Balance Sheets. This amount is exclusive of insurance retentions and $i834 million of insurance proceeds we received through December 31, 2020. We intend to pursue the full extent of our insurance coverage for the costs we have incurred. Other than insurance for certain future defense costs we may incur as well as directors’ and officers’ liability, we have exhausted
all of our insurance in this matter. We continue to pursue other sources of insurance coverage for costs related to this matter, but we may not be successful in obtaining additional insurance recovery for any of these costs. If we are not able to secure additional insurance recovery, if any costs we have recorded as an insurance receivable are not collected, if there are delays in receiving insurance recoveries, or if the insurance recoveries are subject to income taxes while the associated costs are not tax deductible, such amounts, which could be significant, could have a material adverse effect on SoCalGas’ and Sempra 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 Regas Facility that allegedly
overlaps with land owned by the ECA Regas Facility (the facility, however, is not situated on the land that is the subject of this dispute). A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of SEDATU in 2006 to issue title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title 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 and ordered a retrial.
iFour
other cases involving two adjacent areas of real property on which part of the ECA Regas Facility is situated, each brought by a single plaintiff or her descendants, remain pending against the facility. The first disputed area is subject to a claim in the federal Agrarian Court that has been ongoing since 2006, in which the plaintiffs seek to annul the property title for a portion of the land on which the ECA Regas Facility is situated and to obtain possession of a different parcel that allegedly overlaps with the site of the ECA Regas Facility. The second disputed area is one parcel adjacent to the ECA Regas Facility that allegedly overlaps with land on which the ECA Regas Facility is situated, which is subject to a claim in the Agrarian Court and two claims in civil courts. The Agrarian Court proceeding, which seeks an order that SEDATU issue title to the plaintiff, was initiated in 2013 and the parties are awaiting a final decision. The two civil court proceedings,
which seek to invalidate the contract by which the ECA Regas Facility purchased the applicable parcel of land on which the ECA Regas Facility is situated on the grounds that the purchase price was allegedly unfair, are progressing at different stages. In the first, initiated in 2013, a lower court ruled in favor of the ECA Regas Facility and the ruling has been appealed by the plaintiff. The same plaintiff filed the second civil case in 2019, which is in its initial stages.
Certain of these land disputes involve land on which portions of the ECA LNG liquefaction facilities are proposed to be situated or on which portions of the ECA Regas Facility that would be necessary for the operation of the proposed ECA LNG liquefaction facilities are situated.
Several administrative challenges are pending before Mexico’s Secretariat of Environment and Natural Resources (the Mexican environmental
protection agency) and Federal Tax and Administrative Courts, seeking revocation of the environmental impact
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authorization issued to the ECA Regas Facility in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.
In 2018, itwo
related claimants filed separate challenges in the federal district court in Ensenada, Baja California in relation to the environmental and social impact permits issued by each of Agencia de Seguridad, Energía y Ambiente (ASEA) and SENER to ECA LNG authorizing natural gas liquefaction activities at the ECA Regas Facility. In the first case, the court issued a provisional injunction in September 2018. In December 2018, ASEA approved modifications to the environmental permit that facilitate the development of the proposed natural gas liquefaction facility in two phases. In May 2019, the court canceled the provisional injunction. The claimant appealed the court’s decision canceling the injunction, but was not successful. The claimant’s underlying challenge to the permits remains pending. In the second case, the initial request for a provisional injunction was denied. That decision was reversed on appeal in January 2020, resulting in the issuance of a new injunction against
the same environmental and social impact permits that were already issued by ASEA and SENER. This injunction has uncertain application absent clarification by the court. The reversal and issuance of the injunction in the second case is under further appeal.
In September 2020, parties claiming a property interest in the land on which the ECA Regas Facility is situated and the proposed ECA LNG liquefaction facilities are anticipated to be situated filed an administrative proceeding with the Municipality of Ensenada against the permit for the construction of the proposed liquefaction export projects at the ECA Regas Facility. The ECA Regas Facility and ECA LNG contested the validity of the claim and the Municipality of Ensenada has confirmed the validity of the construction permit and closed the proceeding.
In May 2020, the two third-party capacity customers at the ECA Regas Facility,
Shell Mexico and Gazprom, asserted that a 2019 update of the general terms and conditions for service at the facility, as approved by the CRE, resulted in a breach of contract by IEnova and a force majeure event. Citing these circumstances, the customers subsequently stopped making payments of amounts due under their respective LNG storage and regasification agreements. IEnova has rejected the customers’ assertions and has drawn (and expects to continue to draw) on the customers’ letters of credit provided as payment security. The parties engaged in discussions under the applicable contractual dispute resolution procedures without coming to a mutually acceptable resolution. In July 2020, Shell Mexico submitted a request for arbitration of the dispute and although Gazprom has joined the proceeding, Gazprom has replenished the amounts drawn on its letter of credit and has resumed making regular monthly payments under its LNG storage and regasification agreement. IEnova
intends to avail itself of its available claims, defenses, rights and remedies in the arbitration proceeding, including seeking dismissal of the customers’ claims. In addition to the arbitration proceeding, Shell Mexico also filed a constitutional challenge to the CRE’s approval of the update to the general terms and conditions. In October 2020, Shell Mexico’s request to stay CRE’s approval was denied and, subsequently, Shell Mexico filed an appeal of that decision.
One or more unfavorable final decisions on these disputes or challenges could materially and adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the site of the ECA Regas Facility.
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 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 in August 2019.
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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. Subsequently, IEnova and the CFE agreed to extend the service start date to May 15, 2020 and then again to September 15, 2020. In the third quarter of 2020, the parties agreed to further extend the service start date to March 14, 2021. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is repaired. If the pipeline is not repaired by March 14, 2021 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. At December 31, 2020, the Guaymas-El Oro segment of the Sonora pipeline had a net book value of $i447 million. The Sasabe-Puerto Libertad-Guaymas segment of the Sonora pipeline remains
in full operation and is not impacted by these developments.
Regulatory Actions by the Mexican Government that Impact Renewable Energy Facilities
In April 2020, Mexico’s CENACE issued an order that it claims would safeguard Mexico’s national power grid from interruptions that may be caused by renewable energy projects. The main provision of the order suspends all legally mandated pre-operative testing that would be needed for new renewable energy projects to commence operations and prevents such projects from connecting to the national power grid until further notice. IEnova’s renewable energy projects affected by the order filed for legal protection through amparo claims (constitutional protection lawsuits) and, in June 2020, received injunctive relief until the claims are resolved by the courts. We have since achieved commercial operations on two solar power generation projects,
Tepezalá and Don Diego, and expect to achieve commercial operations on Border Solar in the first half of 2021. The second phase of ESJ is not impacted by the order because it is not interconnected to the Mexican electric grid.
In May 2020, Mexico’s SENER published a resolution to establish guidelines intended to guarantee the security and reliability of the national grid’s electricity supply by reducing the threat that it claims is caused by clean, intermittent energy. IEnova’s renewable energy projects, including those in construction and in service, filed amparo claims against the SENER resolution in June 2020 and received injunctive relief in July 2020. In addition, in June 2020, COFECE, Mexico’s antitrust regulator, filed a complaint with Mexico’s Supreme Court against the SENER resolution. The court accepted COFECE’s complaint and, in February 2021, issued its final ruling that the main proposed changes in the SENER resolution
are unconstitutional.
In May 2020, the CRE approved an update to the transmission rates included in legacy renewables and cogeneration energy contracts, based on the claim that the legacy transmission rates did not reflect fair and proportional costs for providing the applicable services and, therefore, created inequitable competitive conditions. Three of IEnova’s renewables facilities are currently holders of contracts with such legacy rates, and any increases in the transmission rates would be passed through directly to their customers. IEnova filed amparo claims for its affected facilities and, in August 2020, was granted injunctive relief.
IEnova and other companies affected by these new orders and regulations have challenged the orders and regulations by filing amparo claims, some of which have been granted injunctive relief. The court-ordered injunctions provide relief until
Mexico’s Federal District Court ultimately resolves the amparo claims. An unfavorable final decision on these amparo challenges, or the potential for an extended dispute, could impact our ability to successfully complete construction of our Border Solar project, which is not yet commercially operating, or to complete such construction in a timely manner and within expected budgets, may impact our ability to operate our wind and solar facilities already in service at existing levels or at all, and may adversely affect our ability to develop new projects, any of which may have a material adverse impact on our results of operations and cash flows and our ability to recover the carrying values of our renewable energy investments in Mexico.
In October 2020, the CRE approved a resolution to amend the rules for the inclusion of new offtakers of legacy generation and self-supply permits (the Offtaker Resolution), which became effective
immediately. The Offtaker Resolution prohibits self-supply permit holders from adding new offtakers that were not included in the original development or expansion plans, making modifications to the amount of energy allocated to the named offtakers, and including load centers that have entered into a supply arrangement under Mexico’s Electricity Industry Law. Don Diego Solar and Border Solar (two of IEnova’s projects, the first of which has achieved commercial operations and the second of which is currently in construction) and the Ventika wind power generation facilities are holders of legacy self-supply permits and are impacted by the Offtaker Resolution. If IEnova is not able to obtain legal protection for these impacted facilities, IEnova expects it will sell Border Solar’s capacity and a portion of Don Diego Solar’s capacity affected by the Offtaker Resolution into the spot market. Currently, prices in the spot market are significantly
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lower
than the fixed prices in the PPAs that were entered into through self-supply permits. IEnova has filed lawsuits against the Offtaker Resolution. Currently, Border Solar and Don Diego Solar are prohibited from delivering electric power to all (with respect to Border Solar) or a portion (with respect to Don Diego Solar) of their respective offtakers pending final resolution of these lawsuits. IEnova is evaluating ways to obtain injunctive relief that would allow Border Solar and Don Diego Solar to deliver electric power to their offtakers pending a final decision in the lawsuits.
Other Litigation
RBS Sempra Commodities
Sempra Energy holds an equity method investment in RBS Sempra Commodities, a limited liability partnership
in the process of being liquidated. RBS, now NatWest Markets plc, our partner in the JV, paid an assessment of Łi86 million (approximately $i138 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 J.P. Morgan Chase & Co. and later to Mercuria Energy Group, Ltd. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid on certain carbon credit purchases during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. After paying the assessment, RBS filed a Notice of Appeal of the assessment with the First-Tier Tribunal. Trial on the matter, which could include the assessment of a penalty of up to i100%
of the claimed amount, is scheduled to begin in June 2021.
In 2015, liquidators filed a claim in the High Court of Justice against RBS and Mercuria Energy Europe Trading Limited (the Defendants) on behalf of 10 companies (the Liquidating Companies) that engaged in carbon credit trading via chains that included a company that traded directly with RBS SEE. The claim alleges that the Defendants’ participation in the purchase and sale of carbon credits resulted in the Liquidating Companies’ carbon credit trading transactions creating a VAT liability they were unable to pay, and that the Defendants are liable to provide for equitable compensation due to dishonest assistance and for compensation under the U.K. Insolvency Act of 1986. Trial on the matter was held in June and July of 2018. In March 2020, the High Court of Justice rendered its judgment mostly in favor of the Liquidating Companies and awarded damages of approximately
Łi45 million (approximately $i61 million in U.S. dollars at December 31,
2020), plus costs and interest. In October 2020, the High Court of Justice issued an order granting the Defendants permission to appeal its March 2020 judgment to the Court of Appeal, and the Defendants have filed an application for such appeal.
Although the final outcome of both the High Court of Justice case and First-Tier Tribunal case remains uncertain, we recorded $i100 million in equity losses from our investment in RBS Sempra Commodities in Equity Earnings on the Sempra Energy Consolidated
Statement of Operations in the year ended December 31, 2020, which represents an estimate of our obligations to settle pending tax matters and related legal costs.
Asbestos Claims Against EFH Subsidiaries
Certain EFH subsidiaries that we acquired as part of the merger of EFH with an indirect subsidiary of Sempra Energy are defendants in personal injury lawsuits brought in state courts throughout the U.S. As of February 22, 2021, i209
such lawsuits are pending with i77 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 i28,000
proofs of claim were filed on behalf of persons who allege exposure to asbestos under similar circumstances and assert the right to file such lawsuits in the future. None of these claims or lawsuits were discharged in the EFH bankruptcy proceeding. The costs to defend or resolve these lawsuits and the amount of damages that may be imposed or incurred could have a material adverse effect on Sempra Energy’s cash flows, financial condition and results of operations.
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
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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 i20 years, or to terminate the lease within
ione year. Our lease liabilities and ROU assets are based on lease terms that may include such options when it is reasonably certain that we will exercise the option.
iCertain 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 i2% to i4%
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 $ii297/ million
in each of 2021 and 2022, $i296 million in 2023, $i297 million in 2024, $i296 million
in 2025 and $i3,069 million thereafter.
As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal
to the lease payments in a similar economic environment. We also record a corresponding ROU asset, initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. We test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.
For our operating leases, our non-regulated entities recognize a single lease cost on a straight-line basis over the lease term in operating expenses. 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.
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i
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.
LESSEE
INFORMATION ON THE CONSOLIDATED BALANCE SHEETS
(2) Included in O&M, except for $ii18/ million
in 2020 and $ii15/ million
in 2019, which is included in Depreciation and Amortization Expense at Sempra Energy Consolidated and SDG&E.
(3) Short-term leases with variable lease costs are recorded and presented as variable lease costs.
/
i
Cash paid for amounts included in the measurement of lease liabilities was as follows:
LESSEE
INFORMATION ON THE CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
Sempra Energy Consolidated
SDG&E
SoCalGas
Years ended December 31
2020
2019
2020
2019
2020
2019
Operating
activities:
Cash paid for operating leases
$
i79
$
i101
$
i31
$
i33
$
i24
$
i27
Cash
paid for finance leases
i173
i173
i171
i173
i2
i—
Financing
activities:
Cash paid for finance leases
i35
i24
i23
i18
i12
i6
Increase
(decrease) in operating lease obligations for right-of-use assets
i20
i585
(i1)
i158
i1
i118
Increase
in finance lease obligations for investment in
PP&E
i77
i38
i30
i16
i47
i22
/
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ii
The
table below presents the maturity analysis of our lease liabilities and reconciliation to the present value of lease liabilities:
The
annual amortization charge for PPAs accounted for as capital leases at both Sempra Energy Consolidated and SDG&E was $ii11/
million in 2018. The annual depreciation charge for fleet vehicles and other assets in 2018 was $i8 million at Sempra Energy Consolidated, including $i2
million at SDG&E and $i6 million at SoCalGas.
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.
iGenerally, 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 in amount from one period to the next.
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i
We
provide information below for leases for which we are the lessor.
(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 2032.
Sempra LNG has various capacity agreements for natural gas storage and transportation. Transportation costs on these agreements vary based on pipeline capacity.
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Payments on our natural gas contracts could exceed the minimum commitment based on portfolio needs. iAt
December 31, 2020, the future minimum payments under existing natural gas contracts and natural gas storage and transportation contracts are as follows:
FUTURE MINIMUM PAYMENTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
Storage
and transportation
Natural gas(1)
Total(1)
2021
$
i216
$
i61
$
i277
2022
i203
i13
i216
2023
i189
i12
i201
2024
i166
i12
i178
2025
i131
i6
i137
Thereafter
i1,014
i—
i1,014
Total
minimum payments
$
i1,919
$
i104
$
i2,023
(1)Excludes
amounts related to the LNG purchase agreement discussed below.
FUTURE MINIMUM PAYMENTS – SOCALGAS
(Dollars in millions)
Transportation
Natural
gas
Total
2021
$
i134
$
i41
$
i175
2022
i126
i—
i126
2023
i123
i—
i123
2024
i103
i—
i103
2025
i68
i—
i68
Thereafter
i359
i—
i359
Total
minimum payments
$
i913
$
i41
$
i954
i
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:
Sempra LNG has a sale and purchase agreement for the supply of LNG to the ECA Regas Facility. The commitment amount is calculated using a predetermined formula based on estimated forward prices of the index applicable from 2021 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.
i
At December 31, 2020, 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:
LNG COMMITMENT AMOUNTS
(Dollars in millions)
2021
$
i320
2022
i422
2023
i389
2024
i386
2025
i390
Thereafter
i1,452
Total
$
i3,359
/
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Actual
LNG purchases in 2020, 2019 and 2018 have been significantly lower than the maximum amount provided under the agreement due to the customer electing to divert cargoes as allowed by the agreement.
Purchased-Power Contracts
For 2021, SDG&E expects to meet its customer power requirements from the following resource types:
▪Long-term contracts: i28% (of which i27%
is provided by renewable energy contracts expiring on various dates through 2041)
▪Other SDG&E-owned generation and tolling contracts: i43%
▪Spot market purchases: i29%
Payments
on our purchased-power contracts could exceed the minimum commitments based on energy needs. iAt December 31, 2020, 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. SDG&E estimates these variable payments to be $ii66/ million
in each of 2021 and 2022, $i67 million in 2023, $i65 million in 2024, $i66 million
in 2025 and $i541 million thereafter. Total payments under purchased-power contracts for Sempra Energy Consolidated and SDG&E were $i534
million in 2020, $i744 million in 2019 and $i712 million
in 2018.
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, 2020 under these projects are approximately $i696 million, requiring future payments of $i525
million in 2021, $i22 million in 2022, $i19
million in 2023, $ii16/
million in each of 2024 and 2025 and $i98 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to such projects.
SDG&E
At December 31, 2020, SDG&E has commitments to make future payments of $i25
million for construction projects that include:
▪$i1 million for infrastructure improvements for electric and natural gas transmission and distribution systems; and
▪$i24
million related to spent fuel management at SONGS.
SDG&E expects future payments under these contractual commitments to be $i2 million in 2021, $iiii1///
million in each of 2022 through 2025 and $i19 million thereafter.
Sempra Mexico
At December 31, 2020, Sempra Mexico has commitments to make future payments of $i610
million for construction projects that include:
▪$i349 million for liquid fuels terminals;
▪$i249
million for natural gas pipelines and ongoing maintenance services; and
▪$i12 million for renewables projects.
Sempra Mexico expects future payments under these contractual commitments to be $i466
million in 2021, $i19 million in 2022, $i16
million in 2023, $ii15/
million in each of 2024 and 2025 and $i79 million thereafter.
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Sempra LNG
At December 31, 2020, Sempra LNG has commitments to make future payments of $i61
million primarily for natural gas liquefaction development costs and natural gas transportation projects. Sempra LNG expects future payments under these contractual commitments to be $i57 million in 2021, $ii2/
million in each of 2022 and 2023.
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 $iiiii4////
million per year in 2021 through 2025 and $i279 million thereafter, subject to escalation of i2% per year, for a remaining i49-year
period. At December 31, 2020, the present value of these future payments of $i121 million has been recorded as a regulatory asset as the amounts represent a cost that we expect will be recovered from customers in the future.
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 i18 years beginning in 2011, Sempra LNG would sell to the California Utilities, subject to annual CPUC approval, up to i500 MMcf per day of regasified LNG from Sempra Mexico’s ECA Regas Facility that is not delivered or sold
in Mexico at the price indexed to the California border minus $i0.02 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 disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions, exclusive of interest and costs, exceed the lesser of $i1 million or 1% of current assets, which was $i45
million for Sempra Energy Consolidated, $i16 million for SDG&E and $i15
million for SoCalGas at December 31, 2020.
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.”
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Other Environmental Issues
iWe
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. iThe 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.
i
The
table below shows the status at December 31, 2020 of the California Utilities’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:
STATUS OF ENVIRONMENTAL SITES
# Sites
complete(1)
# Sites in process
SDG&E:
Manufactured-gas
sites
i3
i—
Third-party
waste-disposal sites
i2
i1
SoCalGas:
Manufactured-gas
sites
i39
i3
Third-party
waste-disposal sites
i5
i2
(1) There
may be ongoing compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.
/
We record environmental liabilities when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and
cleanups proceed, we make adjustments as necessary.
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i
The following table shows our accrued liabilities for environmental matters at December 31, 2020. Of the total liability, $i9
million at SoCalGas is recorded on a discounted basis, with a discount rate of i1.5%.
ACCRUED
LIABILITIES FOR ENVIRONMENTAL MATTERS
(Dollars in millions)
Manufactured- gas sites
Waste
disposal
sites (PRP)(1)
Other hazardous waste sites
Total(2)
SDG&E(3)
$
i—
$
i6
$
i13
$
i19
SoCalGas(4)
i36
i3
i1
i40
Other
i—
i1
i—
i1
Total
Sempra Energy
$
i36
$
i10
$
i14
$
i60
(1) Sites
for which we have been identified as a PRP.
(2) Includes $i11 million, $i1
million and $i10 million classified as current liabilities, and $i49 million, $i18
million and $i30 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. 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 $i84
million, of which $i47 million has been incurred through December 31, 2020 and $i37
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.
We expect future payments related to our environmental liabilities on an undiscounted basis to be $i12 million in 2021, $i16
million in 2022, $i3 million in 2023, $i6
million in 2024, $i3 million in 2025 and $i58
million thereafter.
NOTE 17. iSEGMENT
INFORMATION
i
We have ifive separately managed reportable segments, as follows:
▪SDG&E
provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
▪SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
▪Sempra Texas Utilities holds our investment in Oncor Holdings, which owns an i80.25% interest in Oncor, a regulated electric
transmission and distribution utility serving customers in the north-central, eastern, western and panhandle regions of Texas; and our indirect, i50% interest in Sharyland Holdings, which owns Sharyland Utilities, a regulated electric transmission utility serving customers near the Texas-Mexico border. As we discuss in Note 5, we acquired our investment in Sharyland Holdings in May 2019.
▪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.
▪Sempra LNG develops and builds natural gas liquefaction export facilities, 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 April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments. Upon completion of this sale, remaining nominal business activities at Sempra Renewables were subsumed into Parent and other and the Sempra Renewables segment ceased to exist.
The tables below include amounts from Sempra Renewables up until cessation of the segment.
As we discuss in Note 5, the financial information related to our businesses that constituted the Sempra South American Utilities segment is presented as discontinued operations for all periods presented. The information in the tables below excludes amounts from discontinued operations unless otherwise noted. We completed the sales of our discontinued operations in the second quarter of 2020.
/
F-150
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.
iThe
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 $i5 million, $i88 million, $i91
million and $i136 million for 2020; $i5 million, $i69
million, $i120 million and $i222 million for 2019; and $i4
million, $i64 million, $i114 million and $i215
million for 2018 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG, respectively.
(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.
F-153
NOTE
18. iQUARTERLY FINANCIAL DATA (UNAUDITED)
i
We provide quarterly financial information
for Sempra Energy Consolidated, SDG&E and SoCalGas below:
SEMPRA ENERGY
(In millions, except per share amounts)
Quarters ended
March
31
June 30
September 30
December 31
2020:
Revenues
$
i3,029
$
i2,526
$
i2,644
$
i3,171
Expenses
and other income
$
i2,632
$
i2,063
$
i2,443
$
i2,743
Income
from continuing operations, net of income tax
$
i867
$
i528
$
i428
$
i432
Income
(loss) from discontinued operations, net of income tax
i80
i1,777
(i7)
i—
Net
income
$
i947
$
i2,305
$
i421
$
i432
Earnings
attributable to common shares
$
i760
$
i2,239
$
i351
$
i414
Basic
EPS(1):
Earnings from continuing operations
$
i2.35
$
i1.58
$
i1.23
$
i1.43
Earnings
(losses) from discontinued operations
$
i0.25
$
i6.06
$
(i0.02)
$
i—
Earnings
$
i2.60
$
i7.64
$
i1.21
$
i1.43
Weighted-average
common shares outstanding
i292.8
i293.1
i289.5
i289.0
Diluted
EPS(1):
Earnings from continuing operations(2)
$
i2.30
$
i1.58
$
i1.23
$
i1.43
Earnings
(losses) from discontinued operations
$
i0.23
$
i6.03
$
(i0.02)
$
i—
Earnings(2)
$
i2.53
$
i7.61
$
i1.21
$
i1.43
Weighted-average
common shares outstanding
i313.9
i294.2
i290.6
i290.2
2019:
Revenues
$
i2,898
$
i2,230
$
i2,758
$
i2,943
Expenses
and other income
$
i2,397
$
i1,944
$
i2,310
$
i2,444
Income
from continuing operations, net of income tax
$
i560
$
i357
$
i653
$
i429
(Loss)
income from discontinued operations, net of income tax
(i42)
i78
i256
i71
Net
income
$
i518
$
i435
$
i909
$
i500
Earnings
attributable to common shares
$
i441
$
i354
$
i813
$
i447
Basic
EPS(1):
Earnings from continuing operations
$
i1.79
$
i1.03
$
i2.04
$
i1.36
(Losses)
earnings from discontinued operations
$
(i0.19)
$
i0.26
$
i0.89
$
i0.21
Earnings
$
i1.60
$
i1.29
$
i2.93
$
i1.57
Weighted-average
common shares outstanding
i274.7
i275.0
i277.4
i284.6
Diluted
EPS(1):
Earnings from continuing operations(2)
$
i1.78
$
i1.01
$
i2.00
$
i1.34
(Losses)
earnings from discontinued operations
$
(i0.19)
$
i0.25
$
i0.84
$
i0.21
Earnings(2)
$
i1.59
$
i1.26
$
i2.84
$
i1.55
Weighted-average
common shares outstanding
i277.2
i279.6
i295.8
i288.8
(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 March 31, 2020 and September 30, 2019, 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 dividends declared in those quarters.
/
F-154
In
April 2020, we completed the sale of our equity interests in our Peruvian businesses for cash proceeds of $i3,549 million, net of transaction costs and as adjusted for post-closing adjustments, and recorded a pretax gain of $i2,271 million
($i1,499 million after tax). In June 2020, we completed the sale of our equity interests in our Chilean businesses for cash proceeds of $i2,216 million,
net of transaction costs and as adjusted for post-closing adjustments, and recorded a pretax gain of $i628 million ($i248 million
after tax). We discuss the sale of these discontinued operations and related gains in Note 5.
In March, September and December of 2020, SoCalGas recorded charges of $i100 million ($i72 million
after tax), $i27 million ($i22 million after tax) and $i180 million
($i139 million after tax), respectively, in Aliso Canyon Litigation and Regulatory Matters on the SoCalGas and Sempra Energy Consolidated Statements of Operations related to settlement discussions in connection with civil litigation and regulatory matters. We discuss these matters in Note 16.
In April 2019, Sempra Renewables completed the sale of its remaining wind assets and investments and recognized a pretax gain on sale of $i61
million ($i45 million after tax). We discuss the sale and related gain in Note 5.
SDG&E
(Dollars
in millions)
Quarters ended
March 31
June 30
September 30
December 31
2020:
Operating
revenues
$
i1,269
$
i1,235
$
i1,472
$
i1,337
Operating
expenses
i880
i887
i1,157
i1,016
Operating
income
$
i389
$
i348
$
i315
$
i321
Net
income/Earnings attributable to common shares
$
i262
$
i193
$
i178
$
i191
2019:
Operating
revenues
$
i1,145
$
i1,094
$
i1,427
$
i1,259
Operating
expenses
i883
i831
i1,004
i894
Operating
income
$
i262
$
i263
$
i423
$
i365
Net
income
$
i177
$
i146
$
i266
$
i185
Earnings
attributable to noncontrolling interest
(i1)
(i3)
(i3)
i—
Earnings
attributable to common shares
$
i176
$
i143
$
i263
$
i185
SOCALGAS
(Dollars
in millions)
Quarters ended
March 31
June 30
September 30
December 31
2020:
Operating
revenues
$
i1,395
$
i1,010
$
i842
$
i1,501
Operating
expenses
i1,031
i773
i826
i1,333
Operating
income
$
i364
$
i237
$
i16
$
i168
Net
income (loss)
$
i303
$
i147
$
(i24)
$
i79
Dividends
on preferred stock
i—
(i1)
i—
i—
Earnings
(losses) attributable to common shares
$
i303
$
i146
$
(i24)
$
i79
2019:
Operating
revenues
$
i1,361
$
i806
$
i975
$
i1,383
Operating
expenses
i1,060
i747
i762
i1,000
Operating
income
$
i301
$
i59
$
i213
$
i383
Net
income
$
i264
$
i31
$
i143
$
i204
Dividends
on preferred stock
i—
(i1)
i—
i—
Earnings
attributable to common shares
$
i264
$
i30
$
i143
$
i204
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.
F-155
SCHEDULE I – SEMPRA ENERGY
INDEX TO CONDENSED FINANCIAL INFORMATION OF PARENT
Net cash (used in) provided by operating activities
(i978)
$
i294
$
i213
Expenditures
for property, plant and equipment
(i9)
(i8)
(i11)
Expenditures
for acquisition
i—
i—
(i329)
Capital
contributions to investees
(i364)
(i1,528)
(i9,457)
Distribution
from investments
i3,616
i—
i—
Decrease
(increase) in loans to affiliates, net
i2
i—
(i1)
Other
i—
i4
i—
Net
cash provided by (used in) investing activities
i3,245
(i1,532)
(i9,798)
Common
stock dividends paid
(i1,174)
(i993)
(i877)
Preferred
dividends paid
(i157)
(i142)
(i89)
Issuances
of preferred stock, net
i891
i—
i2,258
Issuances
of common stock, net
i11
i1,830
i2,272
Repurchases
of common stock
(i566)
(i26)
(i21)
Issuances
of long-term debt
i1,599
i758
i4,969
Payments
on long-term debt
(i3,700)
(i1,500)
(i500)
Increase
in loans from affiliates, net
i1,194
i1,328
i1,520
Equity
transaction costs with third parties
(i4)
i—
i—
Debt
issuance costs
(i1)
(i25)
(i37)
Net
cash (used in) provided by financing activities
(i1,907)
i1,230
i9,495
Increase
(decrease) in cash and cash equivalents
i360
(i8)
(i90)
Cash
and cash equivalents, January 1
i6
i14
i104
Cash
and cash equivalents, December 31
$
i366
$
i6
$
i14
SUPPLEMENTAL
DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Preferred dividends declared but not paid
$
i47
$
i36
$
i36
Common
dividends issued in stock
i22
i55
i54
Common
dividends declared but not paid
i301
i283
i245
/
See
Notes to Condensed Financial Information of Parent.
S-5
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 (Expense) Income, Net, on the Condensed Statements of Operations includes:
▪$i41
million, $i61 million and $(i6) million of gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans in 2020, 2019 and 2018, respectively;
▪$i3
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
▪$i3 million and $i15
million of losses in 2020 and 2019, respectively, from foreign currency derivatives used to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sale of our operations in Peru and Chile.
Sempra Energy received cash dividends from its consolidated subsidiaries totaling $i300 million, $i150
million and $i300 million in 2020, 2019 and 2018, 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 2020-04, “Facilitation of the Effects of Reference Rate Reform on Financial Reporting”: ASU 2020-04 provides optional expedients and exceptions for applying U.S. GAAP to contract modifications that replace LIBOR or another reference rate affected by reference rate reform and to hedging relationships that reference LIBOR or another reference rate affected or expected to be affected by reference rate reform. ASU 2020-04 was effective March 12, 2020 and can be applied through December 31, 2022, with
certain exceptions for hedging relationships that continue to exist after this date, and may be applied from January 1, 2020. For contract modifications, the standard allows entities to account for modifications as an event that does not require reassessment or remeasurement (i.e., as a continuation of the existing contract). The standard also allows entities to amend their formal designation and documentation of hedging relationships affected or expected to be affected by reference rate reform, without having to de-designate the hedging relationship. Entities may elect the optional expedients and exceptions on an individual hedging relationship basis and independently from one another. We elected the optional expedients for contract modifications. We elected the cash flow hedging expedients to disregard the potential discontinuation of a reference rate when assessing whether a hedged forecasted interest payment is probable
and to disregard certain mismatches between the designated hedging instrument and the hedged item when assessing the hedge effectiveness. We are applying these expedients prospectively from January 1, 2020. Application of these expedients preserves the presentation of derivatives consistent with the past presentation.
ASU 2020-06, “Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity”: ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. In addition to other changes, this standard amends ASC 470-20, “Debt with Conversion and Other Options,” by removing the accounting models for instruments with beneficial conversion features and cash conversion features. The standard also
amends ASC 260, “Earnings Per Share,” as follows:
▪requires an entity to apply the if-converted method when calculating diluted EPS for convertible instruments and no longer use the treasury stock method, which was previously allowed for certain convertible instruments;
S-6
▪requires an entity to include the effect of potential share settlement in the diluted EPS calculation when an instrument may be settled in cash or shares, and no longer allows an entity to rebut the presumption of share settlement if it has a history or policy of cash settlement;
▪requires an entity to include
equity-classified convertible preferred stock that contains down-round features whereby, if the down-round feature is triggered, its effect is treated as a dividend and as a reduction of income available to common shareholders in basic EPS;
▪clarifies that the average market price should be used to calculate the diluted EPS denominator when the exercise price or the number of shares that may be issued is variable, except for certain contingently issuable shares; and
▪clarifies that the weighted-average share count from each quarter should be used when calculating the year-to-date weighted-average share count.
For public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, including interim periods
therein, with early adoption permitted for fiscal years beginning after December 15, 2020. An entity can use either a full or modified retrospective approach to adopt ASU 2020-06 and must disclose, in the period of adoption, EPS transition information about the effect of the change on affected per-share amounts. We plan to adopt the standard on January 1, 2022 and are currently evaluating the effect of the standard on our ongoing financial reporting.
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.
In October 2020, Sempra Energy redeemed $i700 million of floating-rate notes, prior to a scheduled maturity in January 2021, utilizing a portion of the proceeds received from the sales of our South American businesses.
Maturities of long-term debt at December 31, 2020 are $i850
million in 2021, $i500 million in 2022, $i1.0
billion in 2023, $i500 million in 2024, $i350
million in 2025 and $i5.1 billion thereafter.
Additional information on Sempra Energy’s long-term debt is provided in Note 7 of the Notes to Consolidated Financial Statements.
S-7
NOTE
4. COMMITMENTS AND CONTINGENCIES
Sempra Energy has an operating lease commitment related to its corporate headquarters building of approximately $i257 million. Sempra Energy expects payments for its operating lease to be $i10
million in 2021, $i11 million in 2022, $i12 million in 2023, $i12
million in 2024, $i12 million in 2025 and $i200 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.
S-8
Dates Referenced Herein and Documents Incorporated by Reference
