Document/ExhibitDescriptionPagesSize 1: 10-K Annual Report HTML 12.44M
2: EX-4.2 Instrument Defining the Rights of Security Holders HTML 110K
3: EX-4.40 Instrument Defining the Rights of Security Holders HTML 206K
4: EX-10.1 Material Contract HTML 3.13M
5: EX-10.38 Material Contract HTML 282K
6: EX-10.39 Material Contract HTML 284K
7: EX-10.40 Material Contract HTML 283K
8: EX-10.41 Material Contract HTML 276K
9: EX-10.42 Material Contract HTML 276K
10: EX-10.47 Material Contract HTML 213K
11: EX-21.1 Subsidiaries List HTML 56K
12: EX-23.1 Consent of Expert or Counsel HTML 56K
13: EX-23.2 Consent of Expert or Counsel HTML 56K
14: EX-23.3 Consent of Expert or Counsel HTML 56K
15: EX-23.4 Consent of Expert or Counsel HTML 56K
28: EX-99.1 Miscellaneous Exhibit HTML 1.15M
16: EX-31.1 Certification -- §302 - SOA'02 HTML 60K
17: EX-31.2 Certification -- §302 - SOA'02 HTML 60K
18: EX-31.3 Certification -- §302 - SOA'02 HTML 60K
19: EX-31.4 Certification -- §302 - SOA'02 HTML 60K
20: EX-31.5 Certification -- §302 - SOA'02 HTML 60K
21: EX-31.6 Certification -- §302 - SOA'02 HTML 60K
22: EX-32.1 Certification -- §906 - SOA'02 HTML 57K
23: EX-32.2 Certification -- §906 - SOA'02 HTML 57K
24: EX-32.3 Certification -- §906 - SOA'02 HTML 57K
25: EX-32.4 Certification -- §906 - SOA'02 HTML 57K
26: EX-32.5 Certification -- §906 - SOA'02 HTML 57K
27: EX-32.6 Certification -- §906 - SOA'02 HTML 57K
34: R1 Cover HTML 150K
35: R2 Audit Information HTML 61K
36: R3 Consolidated Statements of Operations HTML 177K
37: R4 Consolidated Statements of Comprehensive Income HTML 113K
(Loss)
38: R5 Consolidated Balance Sheets HTML 249K
39: R6 Consolidated Balance Sheets (Parentheticals) HTML 67K
40: R7 Consolidated Statements of Cash Flows HTML 270K
41: R8 Consolidated Statements of Changes in Equity HTML 182K
42: R9 Consolidated Statements of Changes in Equity HTML 63K
(Parenthetical)
43: R10 Consolidated Statements of Operations - SDG&E HTML 104K
44: R11 Consolidated Statements of Comprehensive Income HTML 104K
(Loss) - SDG&E
45: R12 Consolidated Balance Sheets - SDG&E HTML 220K
46: R13 Consolidated Balance Sheets - SDG&E HTML 67K
(Parentheticals)
47: R14 Consolidated Statements of Cash Flows - SDG&E HTML 165K
48: R15 Consolidated Statements of Changes in Equity - HTML 94K
SDG&E
49: R16 Consolidated Statements of Changes in Equity - HTML 58K
SDG&E (Parenthetical)
50: R17 Consolidated Statements of Operations - Scg HTML 112K
51: R18 Consolidated Statements of Comprehensive Income HTML 103K
(Loss) - Scg
52: R19 Consolidated Balance Sheets - Scg HTML 235K
53: R20 Consolidated Balance Sheets - Scg (Parentheticals) HTML 67K
54: R21 Consolidated Statements of Cash Flows - Scg HTML 170K
55: R22 Consolidated Statements of Changes in Equity - Scg HTML 100K
56: R23 Consolidated Statements of Changes in Equity - Scg HTML 60K
(Parenthetical)
57: R24 Significant Accounting Policies and Other HTML 681K
Financial Data
58: R25 New Accounting Standards HTML 70K
59: R26 Revenues HTML 234K
60: R27 Regulatory Matters HTML 202K
61: R28 Acquistions, Divestitures and Discontinued HTML 74K
Operations
62: R29 Investments in Unconsolidated Entities HTML 177K
63: R30 Debt and Credit Facilities HTML 238K
64: R31 Income Taxes HTML 362K
65: R32 Employee Benefit Plans HTML 646K
66: R33 Share-Based Compensation HTML 164K
67: R34 Derivative Financial Instruments HTML 290K
68: R35 Fair Value Measurements HTML 371K
69: R36 Preferred Stock HTML 81K
70: R37 Sempra - Shareholders' Equity and Earnings Per HTML 129K
Common Share
71: R38 San Onofre Nuclear Generating Station HTML 202K
72: R39 Commitments and Contingencies HTML 425K
73: R40 Segment Information HTML 179K
74: R41 Schedule I - Condensed Financial Information of HTML 230K
Parent
75: R42 Significant Accounting Policies and Other HTML 267K
Financial Data (Policies)
76: R43 Significant Accounting Policies and Other HTML 610K
Financial Data (Tables)
77: R44 Revenues (Tables) HTML 215K
78: R45 Regulatory Matters (Tables) HTML 182K
79: R46 Acquistions, Divestitures and Discontinued HTML 71K
Operations (Tables)
80: R47 Investments in Unconsolidated Entities (Tables) HTML 162K
81: R48 Debt and Credit Facilities (Tables) HTML 234K
82: R49 Income Taxes (Tables) HTML 385K
83: R50 Employee Benefit Plans (Tables) HTML 847K
84: R51 Share-Based Compensation (Tables) HTML 152K
85: R52 Derivative Financial Instruments (Tables) HTML 285K
86: R53 Fair Value Measurements (Tables) HTML 366K
87: R54 Preferred Stock (Tables) HTML 66K
88: R55 Sempra - Shareholders' Equity and Earnings Per HTML 124K
Common Share (Tables)
89: R56 San Onofre Nuclear Generating Station (Tables) HTML 109K
90: R57 Commitments and Contingencies (Tables) HTML 465K
91: R58 Segment Information (Tables) HTML 172K
92: R59 Schedule I - Condensed Financial Information of HTML 326K
Parent (Tables)
93: R60 Significant Accounting Policies and Other HTML 58K
Financial Data - Principles of Consolidation
(Details)
94: R61 Significant Accounting Policies and Other HTML 66K
Financial Data - Regulated Operations (Details)
95: R62 Significant Accounting Policies and Other HTML 69K
Financial Data - Cash, Cash Equivalents and
Restricted Cash (Details)
96: R63 Significant Accounting Policies and Other HTML 127K
Financial Data - Credit Losses (Details)
97: R64 Significant Accounting Policies and Other HTML 70K
Financial Data - Inventories (Details)
98: R65 Significant Accounitng Policies and Other HTML 68K
Financial Data - Note Receivable (Details)
99: R66 Significant Accounting Policies and Other HTML 95K
Financial Data - Wildfire Fund (Details)
100: R67 Significant Accounting Policies and Other HTML 158K
Financial Data - Property, Plant, and Equipment
(Details)
101: R68 Significant Accounting Policies and Other HTML 62K
Financial Data - Capitalized Financing Costs
(Details)
102: R69 Significant Accounting Policies and Other HTML 128K
Financial Data - Other Intangible Assets (Details)
103: R70 Significant Accounting Policies and Other HTML 104K
Financial Data - Variable Interest Entities
(Details)
104: R71 Significant Accounting Policies and Other HTML 78K
Financial Data - Asset Retirement Obligations
(Details)
105: R72 Significant Accounting Policies and Other HTML 117K
Financial Data - Changes in Accumulated Other
Comprehensive Income (Details)
106: R73 Significant Accounting Policies and Other HTML 174K
Financial Data - Reclassification From Accumulated
Other Comprehensive Income (Details)
107: R74 Significant Accounting Policies and Other HTML 70K
Financial Data - Other Noncontrolling Interests
(Details)
108: R75 Significant Accounting Policies and Other HTML 211K
Financial Data - Noncontrolling Interests
(Details)
109: R76 Significant Accounting Policies and Other HTML 59K
Financial Data - Foreign Currency Translation
(Details)
110: R77 Significant Accounting Policies and Other HTML 139K
Financial Data - Transactions With Affiliates
(Details)
111: R78 Significant Accounting Policies and Other HTML 93K
Financial Data - Affiliates Revenue and Cost of
Sales (Details)
112: R79 Significant Accounting Policies and Other HTML 122K
Financial Data - Restricted Net Assets (Details)
113: R80 Significant Accounting Policies and Other HTML 83K
Financial Data - Other Income (Expense), Net
(Details)
114: R81 Revenues - Disaggregation of Revenue (Details) HTML 109K
115: R82 Revenues - Performance Obligations (Details) HTML 87K
116: R83 Revenues - Contract Liabilities (Details) HTML 74K
117: R84 Revenues - Receivables From Revenues From HTML 84K
Contracts With Customers (Details)
118: R85 Regulatory Matters - Regulatory Accounts (Details) HTML 126K
119: R86 Regulatory Matters - Covid-19 Pandeminc HTML 95K
Protections and Cpuc Grc (Details)
120: R87 REGULATORY MATTERS - FERC Rate Matters (Details) HTML 62K
121: R88 Regulatory Matters - Cost of Capital & Energy HTML 176K
Efficiency (Details)
122: R89 ACQUISTIONS, DIVESTITURES AND DISCONTINUED HTML 89K
OPERATIONS - Acquisitions (Details)
123: R90 ACQUISTIONS, DIVESTITURES AND DISCONTINUED HTML 75K
OPERATIONS - Divestitures (Details)
124: R91 ACQUISTIONS, DIVESTITURES AND DISCONTINUED HTML 127K
OPERATIONS - Discontinued Operations (Details)
125: R92 Investments in Unconsolidated Entities - Summary HTML 122K
of Investments (Details)
126: R93 Investments in Unconsolidated Entities - Oncor HTML 70K
Holdings (Details)
127: R94 Investments in Unconsolidated Entities - HTML 128K
Summarized Financial Information (Details)
128: R95 Investments in Unconsolidated Entities - Sharyland HTML 69K
Holdings (Details)
129: R96 Investments in Unconsolidated Entities - Cameron HTML 65K
Lng Jv (Details)
130: R97 Investments in Unconsolidated Entities - Sempra HTML 66K
Promissory Note for Sdsra Distribution (Details)
131: R98 Investments in Unconsolidated Entities - Sempra HTML 109K
Support Agreement for Cfin (Details)
132: R99 Investments in Unconsolidated Entities - Rbs HTML 60K
Sempra Commodities (Details)
133: R100 Debt and Credit Facilities - Committed Lines of HTML 140K
Credit (Details)
134: R101 Debt and Credit Facilities - Uncommitted Lines of HTML 78K
Credit (Details)
135: R102 Debt and Credit Facilities - Uncommitted Letters HTML 71K
of Credit (Details)
136: R103 Debt and Credit Facilities - Term Loan (Details) HTML 72K
137: R104 Debt and Credit Facilities - Weighted Average HTML 64K
Interest Rates (Details)
138: R105 Debt and Credit Facilities - Schedule of Long-Term HTML 236K
Debt Instruments (Details)
139: R106 Debt and Credit Facilities - Schedule of HTML 92K
Maturities of Long-Term Debt (Details)
140: R107 Debt and Credit Facilities - Schedule of Callable HTML 66K
Long-Term Debt (Details)
141: R108 Debt and Credit Facilities - First Mortgage Bonds HTML 61K
(Details)
142: R109 Debt and Credit Facilities - First Mortgage Bonds HTML 83K
(Details)
143: R110 Debt and Credit Facilities - Other Long-Term Debt HTML 91K
(Details)
144: R111 Debt and Credit Facilities - Eca Lng Phase 1 HTML 100K
(Details)
145: R112 Debt and Credit Facilities - Ienova Pipelines HTML 65K
(Details)
146: R113 Income Taxes - Reconciliation to Effective Tax HTML 137K
Rate (Details)
147: R114 Income Taxes - Additional Information (Details) HTML 67K
148: R115 Income Taxes - Components of Income Tax Expense HTML 110K
(Benefit) (Details)
149: R116 Income Taxes - Deferred Income Taxes (Details) HTML 128K
150: R117 Income Taxes - Net Operating Losses and Tax Credit HTML 77K
Carryforwards (Details)
151: R118 Income Taxes - Unrecognized Tax Benefits (Details) HTML 82K
152: R119 Income Taxes - Changes in Unrecognized Tax HTML 65K
Benefits (Details)
153: R120 Employee Benefit Plans - Dedicated Assets in HTML 58K
Support of Certain Benefits Plans (Details)
154: R121 Employee Benefit Plans - Pension and Pbop Plans HTML 63K
(Details)
155: R122 Employee Benefit Plans - Projected Benefit HTML 149K
Obligation, Fair Value of Assets and Funded Status
(Details)
156: R123 Employee Benefit Plans - Pension and Pbop HTML 87K
Obligations, Net of Plan Assets (Details)
157: R124 Employee Benefit Plans - Amounts in Accumulated HTML 74K
Other Comprehensive Income (Loss) (Details)
158: R125 Employee Benefit Plans - Obligations of Funded and HTML 87K
Unfunded Pension and Pbop Plans (Details)
159: R126 Employee Benefit Plans - Net Periodic Benefit Cost HTML 141K
and Amounts Recognized in Oci (Details)
160: R127 Employee Benefit Plans - Weighted-Average HTML 90K
Assumptions Used to Determine Benefit Obligation
(Details)
161: R128 Employee Benefit Plans - Weighted-Average HTML 97K
Assumptions Used to Determine Net Periodic Benefit
Cost (Details)
162: R129 Employee Benefit Plans - Assumed Health Care Cost HTML 75K
Trend Rates (Details)
163: R130 Employee Benefit Plans - Target Asset Allocations HTML 79K
for Sempra's Pension Master Trust (Details)
164: R131 Employee Benefit Plans - Narrative (Details) HTML 69K
165: R132 Employee Benefit Plans - Fair Value Measurements, HTML 336K
Investment Assets of Pension Plans (Details)
166: R133 Employee Benefit Plans - Expected Contributions HTML 68K
(Details)
167: R134 Employee Benefit Plans - Expected Benefit Payments HTML 86K
(Details)
168: R135 Employee Benefit Plans - Employer Contributions to HTML 62K
Savings Plans (Details)
169: R136 Share-Based Compensation - Share-Based HTML 179K
Compensation Expense/ Options (Details)
170: R137 SHARE-BASED COMPENSATION - RSAs AND RSUs (Details) HTML 114K
171: R138 Derivative Financial Instruments - Commodity HTML 70K
Volumes (Details)
172: R139 Derivative Financial Instruments - Interest Rate HTML 62K
Derivatives Narrative (Details)
173: R140 Derivative Financial Instruments - Interest Rate HTML 65K
Derivatives (Details)
174: R141 Derivative Financial Instruments - Balance Sheet HTML 141K
(Details)
175: R142 Derivative Financial Instruments - Income HTML 116K
Statement (Details)
176: R143 Derivative Financial Instruments - Cash Flow HTML 67K
Hedges Additional Information (Details)
177: R144 Derivative Financial Instruments - Contingent HTML 63K
Features (Details)
178: R145 Fair Value Measurements - Recurring Fair Value HTML 219K
Measures (Details)
179: R146 Fair Value Measurements - Recon of Level 3 Assets HTML 119K
(Details)
180: R147 Fair Value Measurements - Financial Instruments HTML 110K
(Details)
181: R148 Preferred Stock (Details) HTML 133K
182: R149 Sempra - Shareholders' Equity and Earnings Per HTML 76K
Common Share - Narrative (Details)
183: R150 Sempra - Shareholders' Equity and Earnings Per HTML 141K
Common Share - Earnings (Losses) Per Common Share
Computations (Details)
184: R151 Sempra - Shareholders' Equity and Earnings Per HTML 63K
Common Share - Antidilutive Securities Excluded
From Computation of Eps (Details)
185: R152 Sempra - Shareholders' Equity and Earnings Per HTML 83K
Common Share - Common Stock Activity (Details)
186: R153 San Onofre Nuclear Generating Station - Narrative HTML 68K
(Details)
187: R154 San Onofre Nuclear Generating Station - Nuclear HTML 95K
Decommissioning Trusts (Details)
188: R155 San Onofre Nuclear Generating Station - Asset HTML 69K
Retirement Obligation and Spent Nuclear Fuel
(Details)
189: R156 San Onofre Nuclear Generating Station - Nuclear HTML 68K
Insurance (Details)
190: R157 Commitments and Contingencies - Legal Proceedings HTML 63K
(Details)
191: R158 Commitments and Contingencies - Aliso Canyon HTML 107K
Natural Gas Storage Facility Gas Leak (Details)
192: R159 Commitments and Contingencies - Sonora Pipeline HTML 59K
(Details)
193: R160 Commitments and Contingencies - Offtakers of HTML 60K
Legacy Generation Permits (Details)
194: R161 Commitments and Contingencies - Other Litigation HTML 80K
(Details)
195: R162 Commitments and Contingencies - Leases Balance HTML 137K
Sheet Information (Details)
196: R163 Commitments and Contingencies - Lease Income HTML 85K
Statement Information (Details)
197: R164 Commitments and Contingencies - Leases Cash Flow HTML 75K
Information (Details)
198: R165 Commitments and Contingencies - Lessee Maturity HTML 127K
Analysis of Liabilities (Details)
199: R166 Commitments and Contingencies - Leases That Have HTML 72K
Not Yet Commenced (Details)
200: R167 Commitments and Contingencies - Lessor Information HTML 150K
(Details)
201: R168 Commitments and Contingencies - Contractual HTML 159K
Commitments (Details)
202: R169 Commitments and Contingencies - Other Commitments HTML 89K
(Details)
203: R170 Commitments and Contingencies - Environmental HTML 136K
Issues (Details)
204: R171 Segment Information (Details) HTML 179K
205: R172 Schedule I - Condensed Financial Information of HTML 130K
Parent - Statement of Operations (Details)
206: R173 Schedule I - Condensed Financial Information of HTML 108K
Parent - Statement of Comprehensive Income
(Details)
207: R174 Schedule I - Condensed Financial Information of HTML 140K
Parent - Balance Sheets (Details)
208: R175 Schedule I - Condensed Financial Information of HTML 146K
Parent - Cash Flows (Details)
209: R176 Schedule I - Condensed Financial Information of HTML 163K
Parent - Footnotes (Details)
210: R9999 Uncategorized Items - sre-20221231.htm HTML 77K
213: XML IDEA XML File -- Filing Summary XML 394K
211: XML XBRL Instance -- sre-20221231_htm XML 18.37M
212: EXCEL IDEA Workbook of Financial Reports XLSX 651K
30: EX-101.CAL XBRL Calculations -- sre-20221231_cal XML 672K
31: EX-101.DEF XBRL Definitions -- sre-20221231_def XML 4.44M
32: EX-101.LAB XBRL Labels -- sre-20221231_lab XML 5.71M
33: EX-101.PRE XBRL Presentations -- sre-20221231_pre XML 4.79M
29: EX-101.SCH XBRL Schema -- sre-20221231 XSD 684K
214: JSON XBRL Instance as JSON Data -- MetaLinks 1,272± 2.11M
215: ZIP XBRL Zipped Folder -- 0001032208-23-000008-xbrl Zip 8.23M
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
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
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.
iiiYes//☒
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).
iiiYes//☒
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
2022
Form 10-K| 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☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Sempra
Energy
Yes ☐
No ☐
San Diego Gas & Electric Company
Yes ☐
No ☐
Southern California Gas Company
Yes ☐
No ☐
Indicate
by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).
Sempra Energy
Yes ☐
No ☐
San Diego Gas & Electric Company
Yes ☐
No
☐
Southern California Gas Company
Yes ☐
No ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Sempra Energy
Yes i☐
No
☒
San Diego Gas & Electric Company
Yes i☐
No ☒
Southern California Gas Company
Yes i☐
No
☒
Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2022:
Sempra Energy
$i47.2
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
2022
Form 10-K| 3
Common Stock outstanding, without par value, as of February 21, 2023:
Sempra Energy
i314,569,519
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 2023 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 May 2023 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 doing business as Sempra, 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 such reporting entity makes statements herein only as to itself and its consolidated entities 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. A separate Part II – Item 8
is provided for each reporting entity, except for the Notes to Consolidated Financial Statements, which are combined for all of the reporting entities. All Items other than Part II – Item 8 are combined for the three reporting entities.
Pipeline
and Hazardous Materials Safety Administration
PP&E
property, plant and equipment
PPA
power purchase agreement
PRP
Potentially Responsible Party
PUCT
Public Utility Commission of Texas
PURA
Texas Public Utility Regulatory Act
PXiSE
PXiSE Energy Solutions, LLC
Rating
Agencies
Moody’s, S&P and Fitch, collectively
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
S&P Global Ratings, a division of S&P Global Inc.
SB
California Senate Bill
SDG&E
San Diego Gas & Electric Company
SDSRA
Senior Debt Service Reserve Account
SEC
U.S. Securities and Exchange Commission
SED
Safety
and Enforcement Division of the CPUC
SEDATU
Secretaría de Desarrollo Agrario, Territorial y Urbano (Mexico’s agency in charge of agriculture, land and urban development)
Sempra
Sempra Energy doing business as Sempra, together with its consolidated entities unless otherwise stated or indicated by the context
Sempra California
San Diego Gas & Electric Company and Southern California Gas Company, collectively
Sempra Global
Sempra Global, which was renamed Sempra Infrastructure Partners, LP on September
30, 2021
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’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.
SI Partners
Sempra Infrastructure Partners, LP, the holding company for most of Sempra’s subsidiaries not subject to California or Texas utility regulation, which was formerly named Sempra Global before September 30, 2021
SoCalGas
Southern California Gas Company
SOFR
Secured Overnight Financing Rate
SONGS
San
Onofre Nuclear Generating Station
SPA
sale and purchase agreement
Support Agreement
support agreement, dated July 28, 2020 and amended on June 29, 2021, among Sempra and Sumitomo Mitsui Banking Corporation
TAG
TAG Norte Holding, S. de R.L. de C.V.
Tangguh PSC
Tangguh PSC Contractors
TdM
Termoeléctrica de
Mexicali
Technip Energies
TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of Technip Energies N.V.
Electric Transmission Owner Formula Rate, effective June 1, 2019
TTI
Texas Transmission Investment LLC
U.S. GAAP
generally accepted accounting principles in the United States of America
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” are to Sempra and its consolidated entities, collectively, unless otherwise stated or indicated by the
context. 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;
▪the Financial Statements and related Notes of SDG&E; and
▪the Financial Statements and related Notes of SoCalGas.
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 or implied in any forward-looking statement. 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 otherwise.
Forward-looking statements can be identified by words such as “believes,”“expects,”“intends,”“anticipates,”“contemplates,”“plans,”“estimates,”“projects,”“forecasts,”“should,”“could,”“would,”“will,”“confident,”“may,”“can,”“potential,”“possible,”“proposed,”“in process,”“construct,”“develop,”“opportunity,”“initiative,”“target,”“outlook,”“optimistic,”“maintain,”“continue,”“progress,”“advance,”“goal,”“aim,”“commit,” 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 expressed or implied in any forward-looking statement include risks and uncertainties relating to:
▪California wildfires, including that we may be found liable for damages regardless of fault and that we may not be able to recover all or a substantial portion of costs from insurance, the Wildfire Fund, rates from customers or a combination thereof
▪decisions,
investigations, inquiries, regulations, issuances or revocations of permits or other authorizations, renewals of franchises, and other actions by (i) the CPUC, CRE, DOE, FERC, PUCT, and other governmental and regulatory bodies and (ii) the U.S., Mexico and states, counties, cities and other jurisdictions therein and in other countries in which we do business
▪the success of business development efforts, construction projects and acquisitions and divestitures, including risks in (i) being able to make a final investment decision, (ii) completing construction projects or other transactions on schedule and budget, (iii) realizing anticipated benefits from any of these efforts if completed, and (iv) obtaining the consent or approval of partners or other third parties, including governmental and regulatory bodies
▪litigation,
arbitrations, property disputes and other proceedings, and changes to laws and regulations, including those related to the energy industry in Mexico
▪cybersecurity threats, including by state and state-sponsored actors, of ransomware or other attacks on our systems or the systems of third-parties with which we conduct business, including the energy grid or other energy infrastructure, all of which have become more pronounced due to recent geopolitical events, such as the war in Ukraine
▪our ability to borrow money on favorable terms and meet our debt service obligations, including due to (i) actions by credit rating agencies to downgrade our credit ratings or to place those ratings on negative outlook or (ii) rising interest rates and inflation
▪failure
of foreign governments, state-owned entities and our counterparties to honor their contracts and commitments
▪the impact on affordability of SDG&E’s and SoCalGas’ customer rates and their cost of capital and on SDG&E’s, SoCalGas’ and Sempra Infrastructure’s ability to pass through higher costs to current and future customers due to (i) volatility in inflation, interest rates and commodity prices, (ii) with respect to SDG&E’s and SoCalGas’ businesses, the cost of the clean energy transition in California, (iii) with respect to SDG&E’s business, departing retail load resulting from additional customers transferring to CCA and DA, and (iv) with respect to Sempra Infrastructure’s business, volatility in foreign currency exchange rates
▪the impact of climate and sustainability policies, laws, rules, disclosures,
and trends, including actions to reduce or eliminate reliance on natural gas, increased uncertainty in the political or regulatory environment for California natural gas distribution companies and the risk of nonrecovery for stranded assets
▪our ability to incorporate new technologies into our businesses, including those designed to support governmental and private party energy and climate goals
▪weather, natural disasters, pandemics, accidents, equipment failures, explosions, terrorism, information system outages or other events that disrupt our operations, damage our facilities or systems, cause the release of harmful materials, cause fires or subject us to liability for damages, fines and penalties, some of which may not be recoverable through regulatory mechanisms, may be disputed or not covered by insurers, or may
impact our ability to obtain satisfactory levels of affordable insurance
▪the availability of electric power, natural gas and natural gas storage capacity, including disruptions caused by failures in the transmission grid, pipeline system or limitations on the withdrawal of natural gas from storage facilities
▪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
▪changes in tax and trade policies, laws and regulations, including tariffs, revisions to international trade agreements and sanctions, such as those that have been imposed and that may be imposed in the future in connection with the
war in Ukraine,
which may increase our costs, reduce our competitiveness, impact our ability to do business with certain counterparties, or impair our ability to resolve trade disputes
▪other uncertainties, some of which are difficult to predict and beyond our control
We caution you not to rely unduly on any forward-looking statements.
You should review and carefully consider the risks, uncertainties and other factors that affect our businesses as described herein and in other reports we file with the SEC.
SUMMARY OF RISK FACTORS
There are a number of risks 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 “Part I – Item 1A. Risk Factors” in this report. If any of these risks occurs, Sempra’s and its subsidiaries’ results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, and the trading price of Sempra’s securities and those of its subsidiaries could decline. These risks include the following:
Risks Related to Sempra
▪Sempra’s cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its subsidiaries and entities accounted for as equity method investments
▪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
Risks Related to All Sempra Businesses
▪Our businesses are subject to risks arising from their infrastructure and information systems
▪Severe weather, natural disasters and other similar events could materially adversely affect us
▪Our debt service obligations expose us to risks and could require additional equity securities issuances by Sempra and sales of equity interests in various subsidiaries or projects under development
▪The availability and cost of debt or equity financing
could be negatively affected by market and economic conditions and other factors, and any such effects could materially adversely affect us
▪Credit rating agencies may downgrade our credit ratings or place those ratings on negative outlook
▪Our businesses require numerous permits, licenses, franchises and other approvals from various governmental agencies, and the failure to obtain or maintain any of them, or lengthy delays in obtaining them, could materially adversely affect us
▪Our businesses face climate change concerns and have environmental compliance and clean energy transition costs, which could have a material adverse effect on us
▪Our businesses are subject to numerous
governmental regulations and complex tax and accounting requirements and may be materially adversely affected by them or any changes to them
Risks Related to Sempra California
▪Wildfires in California pose risks to Sempra California (particularly SDG&E) and Sempra
▪The electricity industry is undergoing significant change, including increased deployment of DER, 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 reduce or eliminate reliance on natural gas as an energy source
▪SDG&E
and SoCalGas are subject to extensive regulation by federal, state and local legislative and regulatory authorities, which may materially adversely affect Sempra, SDG&E and SoCalGas
Risks Related to Sempra Texas Utilities
▪Certain ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, operations and policies of Oncor
▪Changes in the regulation or operation of the electric utility industry and/or the ERCOT market, as well as the outcome of regulatory proceedings, could materially adversely affect Oncor, which could materially adversely affect us
▪Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels, any of which could materially adversely affect us
▪We may not be able to enter into, maintain, extend or replace long-term supply, sales or capacity agreements
▪Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical and management oversight risks and challenges
We are a California-based holding company
with energy infrastructure investments in North America. Our businesses invest in, develop and operate energy infrastructure, and provide electric and gas services to customers.
Sempra was formed in 1998 through a business combination of Enova and PE, the holding companies of our regulated public utilities in California: SDG&E, which began operations in 1881, and SoCalGas, which began operations in 1867. We have since expanded our regulated public utility presence into Texas through our 80.25% interest in Oncor and 50% interest in Sharyland Utilities. Sempra Infrastructure’s assets include investments in the U.S. and Mexico with a focus on LNG and net zero solutions, energy networks and clean power.
Business Strategy
Our mission is to be North America’s premier energy infrastructure company. We are primarily focused on transmission
and distribution investments, among other areas, that we believe are capable of producing stable cash flows and earnings visibility, with the goal of delivering safe, reliable and increasingly clean forms of energy to customers and increasing shareholder value.
DESCRIPTION OF BUSINESS BY SEGMENT
Our business activities are organized under the following reportable segments:
▪SDG&E
▪SoCalGas
▪Sempra Texas Utilities
▪Sempra Infrastructure
SDG&E
SDG&E
is a regulated public utility that provides electric services to a population of, at December 31, 2022, approximately 3.6 million and natural gas services to approximately 3.3 million of that population, covering a 4,100 square mile service territory in Southern California that encompasses San Diego County and an adjacent portion of Orange County.
SDG&E’s assets at December 31,
2022 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 1,928 miles of transmission lines, 23,928 miles of distribution lines and 157 substations at December 31, 2022. Occasionally, various areas of the service territory require expansion to accommodate customer
growth and maintain reliability and safety.
SDG&E’s 500-kV Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,163 MW, although it can be less under certain system conditions. SDG&E’s Sunrise Powerlink is a 500-kV transmission line constructed by SDG&E and operated by the California ISO. Both of these lines together provide SDG&E with import capability of 3,900 MW of power.
Mexico’s Baja California transmission system is connected to SDG&E’s system via two 230-kV interconnections with combined capacity of up to 600 MW in the north-to-south direction and 800 MW in the south-to-north direction. However, it can be less under certain system conditions.
Edison’s
transmission system is connected to SDG&E’s system via five 230-kV transmission lines.
Electric Resources. 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 purchases on the spot market. SDG&E does not earn any return on commodity sales volumes. SDG&E’s
electric resources at December 31, 2022 were as follows:
SDG&E – ELECTRIC RESOURCES(1)
Contract
Net operating
expiration date
capacity
(MW)
% of total
Owned generation facilities, natural gas(2)
1,204
24
%
Purchased-power contracts:
Renewables:
Wind
2023 to 2042
1,236
24
Solar
2030
to 2042
1,390
27
Other
2023 and thereafter
37
1
Tolling and other
2024 to 2042
1,206
24
Total
5,073
100
%
(1)Excludes
approximately 321 MW of energy storage owned and approximately 164 MW of energy storage contracted.
(2)SDG&E owns and operates four natural gas-fired power plants, three of which are in California and one 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 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 from various southwestern U.S. suppliers are primarily priced based on published monthly bid-week indices, which
can be subject to volatility.
SDG&E participates in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement that allows access to power trading with more than 300 member utilities, power agencies, energy brokers and power marketers throughout the U.S. and Canada. Participants can make power transactions on standardized terms, including market-based rates, preapproved by the FERC. Participation in the Western Systems Power Pool is intended to assist members in managing power delivery and price risk.
Customers and Demand. SDG&E provides electric services through the generation, transmission and distribution of electricity to the following customer classes:
SDG&E currently provides procurement service for a portion of its customer load. Most customers receive procurement service from a load-serving entity other than SDG&E through programs such as CCA and DA. In such cases, SDG&E no longer procures energy for this departing load. Accordingly, SDG&E’s CCA and DA customers receive primarily transportation and distribution services from SDG&E.
CCA is only available if the customer’s local jurisdiction (city or county) offers such a program and DA is currently limited by a cap based on gigawatt hours. Several jurisdictions in SDG&E's territory have implemented CCA, including the City of San Diego in 2022. Additional jurisdictions are in the process of implementing or considering CCA.
SDG&E’s historical energy procurement for future deliveries exceeds the needs of its remaining bundled customers as customers have elected CCA and DA services. To help achieve the goal of ratepayer indifference (as to whether or not customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The purpose of the framework is to help ensure SDG&E’s procurement cost obligations are more equitably shared among customers served by SDG&E and customers now
served by CCA or DA. SDG&E implemented the framework on January 1, 2019.
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, 2022, 2021 and 2020, the residential and commercial rooftop solar capacity in SDG&E’s territory totaled 1,864 MW, 1,620 MW and 1,423 MW, respectively.
Electricity demand is dependent on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, renewable power generation,
the effectiveness of energy efficiency programs, demand-side management impact and distributed generation resources. California’s energy policy supports increased electrification, particularly electrification of vehicles, which could significantly increase sales volumes in the coming years. Other external factors, such as the price of purchased power, the use of hydroelectric power, the use of and further development of renewable energy resources and energy storage, the development of or requirements for new natural gas supply sources, demand for and supply of natural gas and general economic conditions, can also result in significant shifts in the market price of electricity, which may in turn impact demand. Electricity demand is also impacted by seasonal weather patterns (or “seasonality”), tending to increase in the summer months to meet the cooling load and in the winter months to meet the heating load.
Competition.
SDG&E faces competition to serve its customer load from distributed and local power generation growth, including solar installations. In addition, the electric industry is undergoing rapid technological change, and third-party energy storage alternatives and other technologies may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering electricity to consumers.
Natural Gas Utility Operations
We describe SDG&E’s natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.”
SoCalGas
SoCalGas is a regulated public utility that owns and operates a natural gas distribution, transmission
and storage system that delivers natural gas to a population of, at December 31, 2022, approximately 21.1 million, covering a 24,000 square mile service territory that encompasses Southern California and portions of central California (excluding San Diego County, the City of Long Beach and the desert area of San Bernardino County).
SoCalGas’ assets at December 31,
2022 covered the following territory:
Natural Gas Utility Operations
We describe SoCalGas’ natural gas utility operations below in “Sempra California’s Natural Gas Utility Operations.”
Sempra California’s Natural Gas Utility Operations
Natural Gas Procurement and Transportation
At December 31, 2022, SoCalGas’ natural gas facilities included 3,046 miles of transmission and storage pipelines,
52,020 miles of distribution pipelines, 48,918 miles of service pipelines and nine transmission compressor stations, and SDG&E’s natural gas facilities consisted of 168 miles of transmission pipelines, 9,112 miles of distribution pipelines, 6,718 miles of service pipelines and one compressor station.
SoCalGas’ and SDG&E’s gas transmission pipelines interconnect with four major interstate pipeline systems: El Paso Natural Gas, Transwestern Pipeline, Kern River Pipeline Company, and Mojave Pipeline Company, allowing customers to bring gas supplies into the SoCalGas gas transmission pipeline system from the various out-of-state gas producing basins. Additionally, an interconnection with PG&E’s intrastate gas transmission pipeline system allows gas to flow into SoCalGas’ gas transmission pipeline system. SoCalGas’ gas transmission pipeline system also has an interconnect with a Mexican gas pipeline company at Otay Mesa
on the California/Mexico border that allows gas to not only flow south from the gas producing basins in the southwestern U.S., but to also flow north into SoCalGas’ gas transmission pipeline system from LNG-sourced supplies in Mexico. There are also several in-state gas interconnections allowing for delivery of California-produced gas, including a number of direct connections from renewable natural gas producers.
SoCalGas purchases natural gas under short-term and long-term contracts and on the spot market for SDG&E’s and SoCalGas’ core customers. SoCalGas purchases natural gas from various sources, including from Canada, the U.S. Rockies and the southwestern regions of the U.S. Purchases of natural gas are primarily priced based on published monthly bid week indices,
which can be subject to volatility. The cost of purchases of natural gas for SDG&E’s and SoCalGas’ core customers is billed to those customers without markup.
To support the delivery of natural gas supplies to its distribution system and to meet the needs of customers, SoCalGas has firm and variable interstate pipeline capacity contracts that require the payment of fixed and variable tariffed and negotiated reservation charges to reserve firm transportation rights. Energy companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company and Kern River Gas Transmission Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas.
Natural
Gas Storage
SoCalGas owns four natural gas storage facilities with a combined working gas capacity of 137 Bcf and 126 injection, withdrawal and observation wells that provide natural gas storage service. SoCalGas’ and SDG&E’s core customers, along with certain third-party market participants, are allocated a portion of SoCalGas’ storage capacity. SoCalGas uses the remaining storage capacity for load balancing services for all customers. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter, as well as peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility has a storage capacity of 86 Bcf and, subject to the CPUC limitations described below, represents 63% of SoCalGas’ natural gas storage capacity. SoCalGas discovered a natural gas leak at one of its wells at the Aliso Canyon natural
gas storage facility in October 2015 and permanently sealed the well in February 2016. SoCalGas was subsequently authorized to make limited withdrawals and injections of natural gas at the Aliso Canyon natural gas storage facility and, on an interim basis, has been directed by the CPUC to maintain up to 41.16 Bcf of working gas at the facility to help achieve reliability for the region 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 reaches defined thresholds for SoCalGas’ system, or public health and safety is at risk, as determined by the protocol. We discuss the Leak in Note 16 of the Notes to Consolidated Financial Statements, in “Part I – Item 1A. Risk Factors” and in “Part II – Item 7. MD&A – Capital Resources and Liquidity – SoCalGas.”
Customers and Demand
SoCalGas
and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers in its territory and SDG&E’s territory on a combined portfolio basis. SoCalGas also offers natural gas transportation and storage services for others.
SEMPRA CALIFORNIA – NATURAL GAS CUSTOMER METERS AND VOLUMES
For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers.
Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase their natural gas supplies from producers,
marketers or brokers, SoCalGas and SDG&E are obligated to maintain adequate delivery capacity to serve the requirements of all their core customers.
Noncore customers at SoCalGas consist primarily of electric generation, wholesale, and large commercial and industrial customers. A portion of SoCalGas’ noncore customers are non-end-users, which include wholesale customers consisting primarily of other utilities, including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial customers.
Noncore customers are responsible for procuring their natural gas requirements, as the regulatory framework does not allow SoCalGas and SDG&E to recover the cost of natural gas procured and delivered to noncore customers.
Natural gas demand largely
depends on the health and expansion of the Southern California economy, prices of alternative energy products, consumer preference, environmental regulations, legislation, California’s energy policy supporting increased electrification and renewable power generation, and the effectiveness of energy efficiency programs. Other external factors such as weather, the price of, demand for, and supply sources of electricity, the use of and further development of renewable energy resources and energy storage, development of or requirements for new natural gas supply sources, demand for natural gas outside California, storage levels, transport capacity and availability of supply into California and general economic conditions can also result in significant shifts in the market price of natural gas, which may in turn impact demand.
One of the larger sources for natural gas demand is electric generation. Natural gas-fired electric generation
within Southern California (and demand for natural gas supplied to such plants) competes with electric power generated throughout the western U.S. Natural gas transported for electric generating plant customers may be affected by the overall demand for electricity, growth in self-generation from rooftop solar, the addition of more efficient gas technologies, new energy efficiency initiatives, and the degree to which regulatory changes in electric transmission infrastructure investment divert electric generation from SoCalGas’ and SDG&E’s service areas. The demand for natural gas may also fluctuate due to volatility in the demand for electricity due to seasonality, weather conditions and other impacts, and the availability of competing supplies of electricity, such as hydroelectric generation and other renewable energy sources. Given the significant quantity of natural gas-fired generation, we believe natural gas is a dispatchable fuel that can continue to help provide
electric reliability in our California service territories.
The natural gas distribution business is subject to seasonality, and cash provided by operating activities generally is greater during and immediately following the winter heating months. As is prevalent in the industry, but subject to current regulatory limitations, SoCalGas typically injects natural gas into storage during the months of April through October, and usually withdraws natural gas from storage during the months of November through March.
Sempra Texas Utilities
Sempra Texas Utilities is comprised of our equity method investments in Oncor Holdings and Sharyland Holdings. Oncor Holdings is an indirect, wholly owned entity of Sempra that owns an 80.25%
interest in Oncor. TTI owns the remaining 19.75% interest in Oncor. Sempra owns an indirect, 50% interest in Sharyland Holdings, which owns a 100% interest in Sharyland Utilities.
Sempra Texas Utilities’ assets at December 31, 2022 covered the following territory:
Oncor
Oncor
is a regulated electricity transmission and distribution utility that operates in the north-central, eastern, western and panhandle regions of Texas. Oncor delivers electricity to end-use consumers through its electrical systems, and also provides transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor’s transmission and distribution assets are located in over 120 counties and more than 400 incorporated municipalities, including the cities of Dallas and Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler, Temple, Killeen and Round Rock, among others. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way pursuant to permits, public utility easements, franchise or other agreements or as otherwise permitted by law.
At December 31,
2022, Oncor had 4,561 employees, including 764 employees covered under a collective bargaining agreement.
Certain ring-fencing measures, governance mechanisms and commitments, which we describe in “Part I – Item 1A. Risk Factors,” are in effect and are intended to enhance Oncor Holdings’ and Oncor’s separateness from their owners and to mitigate the risk that these entities would be negatively impacted by the bankruptcy of, or other adverse financial developments affecting, their owners. Sempra does not control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions, including limited representation on the Oncor Holdings and Oncor
boards of directors. Because Oncor Holdings and Oncor are managed independently (i.e., ring-fenced), we account for our 100% ownership interest in Oncor Holdings as an equity method investment.
Electricity Transmission.Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction, maintenance and security of transmission
facilities
and substations and the monitoring, controlling and dispatching of high-voltage electricity over its transmission facilities in coordination with ERCOT, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.”
At December 31, 2022, Oncor’s transmission system included approximately 18,268 circuit miles of transmission lines, a total of 1,207 transmission and distribution substations, and interconnection to 146 third-party generation facilities totaling 48,430 MW.
Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to limited interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission
business include system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.
Electricity Distribution. Oncor’s electricity distribution business is responsible for the overall safe and reliable operation of distribution facilities, including electricity delivery, power quality, security and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the electricity distribution system within its certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through 3,681 distribution feeders.
Oncor’s distribution system included nearly 3.9 million points of delivery
at December 31, 2022 and consisted of 123,500 miles of overhead and underground lines.
Distribution revenues from residential and small business users are based on actual monthly consumption (kWh) and distribution revenues from large commercial and industrial users are based on, depending on size and annual load factor, either actual monthly demand (kW) or the greater of actual monthly demand (kW) or 80% of peak monthly demand during the prior eleven months.
Customers and Demand. Oncor operates the largest transmission and distribution system in Texas based on the number of end-use customers and miles of transmission and distribution lines, delivering electricity to nearly 3.9 million homes and businesses, operating more than 141,000 miles of transmission and distribution lines as of December 31,
2022 in a territory with an estimated population of approximately 13 million. The consumers of the electricity Oncor delivers (other than ultimate end-use customers served by an electric cooperative or a municipally owned utility) are free to choose their electricity supplier from retail electric providers who compete for their business. Oncor is not a seller of electricity, nor does it purchase electricity for resale. Rather, Oncor provides transmission services to its electricity distribution business as well as non-affiliated electricity distribution companies, cooperatives and municipally owned utilities. Oncor also provides distribution services, consisting of retail delivery services to retail electric providers that sell electricity to end-use customers, as well as wholesale delivery services to cooperatives and municipally owned utilities. At December 31, 2022, Oncor’s distribution business customers primarily
consisted of over 100 retail electric providers that sell the electricity it distributes to consumers in its certificated service areas.
Oncor’s revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.
Competition. Oncor operates in certificated areas designated by the PUCT. The majority of Oncor’s service territory is single certificated, with Oncor as the only certificated electric transmission and distribution provider. However, in multi-certificated areas of Texas, Oncor competes with certain other utilities and rural electric cooperatives for the right to serve end-use customers. In addition, the electric industry is undergoing rapid technological change, and third-party distributed energy resources and other technologies may increasingly compete with
Oncor’s traditional transmission and distribution infrastructure in delivering electricity to consumers.
Sharyland Utilities
Sharyland Utilities is a regulated electric transmission utility that owns and operates, at December 31, 2022, approximately 64 miles of electric transmission lines in south Texas, including a direct current line connecting Mexico and assets in McAllen, Texas. Sharyland Utilities is responsible for providing safe, reliable and efficient transmission and substation services and investing to support infrastructure needs in its service territory, which we discuss below in “Regulation – Utility Regulation – ERCOT Market.” Transmission revenues are provided under tariffs approved by the PUCT.
Sempra
Infrastructure
Our Sempra Infrastructure segment includes the operating companies of our subsidiary, SI Partners, as well as a holding company and certain services companies. SI Partners is included within our Sempra Infrastructure reportable segment, but is not the same in its entirety as the reportable segment. Sempra Infrastructure develops, builds, operates and invests in energy infrastructure to help enable the energy transition in North American markets and globally.
Sempra
Infrastructure owned a 70% interest in SI Partners at December 31, 2022, following its sale of a 20% NCI in SI Partners to KKR in October 2021 and sale of a 10% NCI in SI Partners to ADIA in June 2022. SI Partners has two authorized classes of limited partnership interests designated as “Class A Units” (which are common voting units) and “Sole Risk Interests” (which are only owned by Sempra, are non-voting and are not considered in the calculation of each limited partner’s respective ownership interests, subject to certain restrictions). We discuss KKR’s and ADIA’s purchases of NCI in SI Partners, as well as SI Partners’ limited partnership agreement that governs the partners’ respective rights and obligations in respect of their ownership interests in SI Partners in Note 1 of the Notes to Consolidated Financial Statements.
SI Partners held a 100% ownership interest
in Sempra LNG Holding, LP and a 99.9% ownership interest in IEnova at December 31, 2022, which consolidates Sempra’s ownership and management of its non-utility, energy infrastructure assets in North America under a single platform. These assets include LNG and natural gas infrastructure in the U.S. and Mexico and renewable energy, LPG and refined products infrastructure in Mexico, which are managed through three business lines: LNG and Net-Zero Solutions, Energy Networks and Clean Power.
At December 31, 2022, Sempra Infrastructure owned or held interests in the following assets:
LNG and Net-Zero Solutions
Sempra
Infrastructure’s LNG and Net-Zero Solutions business line is comprised of a natural gas liquefaction portfolio in operation, construction or development, and is focused on energy diversification and the clean energy transition in markets that our customers serve.
Cameron LNG Phase 1 Facility. SI Partners owns 50.2% of Cameron LNG JV, while an affiliate of TotalEnergies SE, an affiliate of Mitsui & Co., Ltd., and Japan LNG Investment, LLC (a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha) each own 16.6% of Cameron LNG JV. We account for our ownership interest in Cameron LNG JV under the equity method. No single owner controls or can unilaterally direct significant activities of Cameron LNG JV.
Cameron LNG JV owns and operates the Cameron LNG Phase 1 facility, a natural gas liquefaction, export, regasification and import
facility with three natural gas pre-treatment, processing and liquefaction trains. The Cameron LNG Phase 1 facility is located in Hackberry, Louisiana, along the Calcasieu Ship Channel, which handles significant industrial shipping, including large
oil and LNG tankers, and is well positioned to supply the Atlantic and Pacific markets. The three liquefaction trains have a combined nameplate capacity of 13.9 Mtpa of LNG with an export capacity of 12
Mtpa of LNG, or approximately 1.7 Bcf of natural gas per day. The Cameron LNG Phase 1 facility has 20-year liquefaction and regasification tolling capacity agreements in place with affiliates of TotalEnergies SE, Mitsubishi Corporation and Mitsui & Co., Ltd., which collectively subscribe for the full nameplate capacity of the three trains at the facility.
ECA Regas Facility. Sempra Infrastructure owns and operates the ECA Regas Facility in Baja California, Mexico, which is capable of processing one Bcf of natural gas per day and has a storage capacity of 320,000 cubic meters in two tanks of 160,000 cubic meters each.
The ECA Regas Facility generates revenues from firm storage service fees under firm storage service agreements and nitrogen injection service agreements with Shell Mexico and Gazprom that expire in 2028, which permit them to collectively use
50% of the terminal’s capacity, with the remaining 50% of the capacity available for Sempra Infrastructure’s use. The land on which the ECA Regas Facility and the ECA LNG liquefaction projects under construction and in development are expected to be situated, as well as land adjacent to those properties, are the subject of litigation. We discuss the ECA Regas Facility arbitration and land litigation in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.”
Sempra Infrastructure uses its 50% capacity at the ECA Regas Facility to satisfy its obligation under an LNG SPA with Tangguh PSC through 2029, which we discuss below, and ECA LNG Phase 1 will be the sole user of this capacity thereafter.
Asset and Supply Optimization. Sempra Infrastructure has an LNG SPA through 2029 with Tangguh PSC for the supply of the equivalent
of 500 MMcf of natural gas per day at a price based on the SoCal Border index for natural gas. The LNG SPA allows Tangguh PSC to divert certain LNG volumes to other global markets in exchange for payments of diversion fees. Sempra Infrastructure may also enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the ECA Regas Facility for sale to other parties. Sempra Infrastructure uses the natural gas produced from this LNG to supply a contract for the sale of natural gas to the CFE at prices that are based on the SoCal Border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, Sempra Infrastructure may purchase natural gas in the market to satisfy such commitment.
Sempra Infrastructure purchases, transports and sells natural gas, and has customers in both the U.S. and Mexico, including the CFE. Sempra Infrastructure may also purchase
natural gas from other Sempra affiliates. Natural gas purchases and transportation arrangements are substantially backed by long-term, U.S. dollar-based contracts for the sale of natural gas to third parties (both U.S. sourced and derived from imported LNG), LNG offtake and natural gas storage and pipeline capacity.
ECA LNG Phase 1 Project. SI Partners owns an 83.4% interest in ECA LNG Phase 1, and an affiliate of TotalEnergies SE owns the remaining 16.6% interest. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We expect the ECA LNG Phase 1 project to commence commercial operations in the summer of 2025.
ECA LNG Phase 1 has definitive 20-year SPAs with an affiliate of TotalEnergies
SE for approximately 1.7 Mtpa of LNG and Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG.
The construction of the ECA LNG Phase 1 project is subject to numerous risks and uncertainties. For a discussion of these risks and uncertainties, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”
Additional Potential LNG and Net-Zero Solutions’ Projects. Sempra Infrastructure is evaluating the following development opportunities:
▪Cameron LNG Phase 2 project, an expansion of the Cameron LNG Phase 1 facility
▪ECA LNG Phase 2 project, a large-scale natural gas liquefaction project to be located at the site of Sempra Infrastructure’s
existing ECA Regas Facility in Baja California, Mexico
▪PA LNG projects, a large-scale natural gas liquefaction project, to be developed in two phases, and associated infrastructure on a greenfield site in the vicinity of Port Arthur, Texas located along the Sabine-Neches waterway
▪Vista Pacifico LNG project, a mid-scale natural gas liquefaction project and associated infrastructure in the vicinity of Topolobampo in Sinaloa, Mexico
▪Hackberry Carbon Sequestration project, a carbon capture and sequestration project that is intended to reduce emissions at the Cameron LNG Phase 1 facility and proposed Cameron LNG Phase 2 project
No final investment decision has been reached for any of these potential projects. The development of these projects is subject to numerous risks and uncertainties. For a discussion of these proposed projects and their risks, see “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”
Demand and Competition. North America benefits from numerous competitive advantages as a potential supplier of LNG to world markets, including the following:
▪high levels of developed and undeveloped natural gas resources, including unconventional natural gas and tight oil
relative to domestic consumption levels
▪flexible and elastic markets in gas and oil drilling and production resulting in efficient unit costs of gas production
▪availability of extensive pre-existing natural gas pipeline transmission systems and natural gas storage capacity with proximity to production locations
Brownfield liquefaction projects also benefit from the particular competitive advantage of the proximity of pre-existing infrastructure, such as LNG tankage and berths.
Global LNG competition may limit North American LNG exports, as international liquefaction projects attempt to match North American LNG production costs and customer contractual rights such as volume and destination flexibility. It is expected that North American
LNG exports will increase competition for current and future global natural gas demand, and thereby facilitate additional growth of a global commodity market for natural gas and LNG.
Cameron LNG JV co-owners and customers compete globally to market and sell LNG to end users, including gas and electric utilities located in LNG-importing countries around the world. By providing liquefaction services, Cameron LNG JV and future LNG export development projects compete indirectly with liquefaction projects currently operating and those under development in the global LNG market. In addition to the U.S., these competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe. The competitive environment shifted in favor of North American LNG development projects in 2022 in the wake of the war in Ukraine and the resulting focus by European markets on alternative supplies. This shift in demand underscores
the attractiveness of long-term contracts from North American LNG projects.
The LNG regasification business is impacted by global LNG market prices. High LNG prices in markets outside the market in which Sempra Infrastructure’s ECA Regas Facility operates have resulted and could continue to result in lower-than-expected deliveries of LNG cargoes to the ECA Regas Facility, which could increase costs if Sempra Infrastructure is instead required to obtain LNG in the open market at prevailing prices. Any inability to obtain expected LNG cargoes could also impact Sempra Infrastructure’s ability to maintain the minimum level of LNG required to keep the ECA Regas Facility in operation at the proper temperature. Prices in international LNG markets through which Sempra Infrastructure must purchase natural gas to meet its contractual obligations to deliver natural gas to customers may also affect how Sempra Infrastructure optimizes its
assets and supply, which could have an adverse impact on its earnings.
Energy Networks
Sempra Infrastructure’s Energy Networks business line is comprised of a natural gas transportation and distribution network.
Cross-Border Interconnections and In-Country Pipelines. Sempra Infrastructure develops, builds, operates and invests in systems for the receipt, transportation, compression and delivery of natural gas and ethane. At December 31, 2022, these systems consisted of 1,850 miles of natural gas transmission pipelines plus 124 miles under construction, 16 natural gas compression stations plus one under construction, and 139 miles of ethane pipelines in Mexico. The design capacity of these pipeline assets is over 16,400 MMcf per day of natural
gas, 204 MMcf per day of ethane gas and 106,000 barrels per day of ethane liquid. Capacity on Sempra Infrastructure’s pipelines and related assets is substantially contracted under long-term, U.S. dollar-based agreements with major industry participants such as the CFE, Centro Nacional de Control de Gas, PEMEX, Gazprom and other similar counterparties. Some of these pipeline assets are affected by disputes related to the property on which the pipelines are located, which we discuss in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.”
Sempra Infrastructure owns a 40-mile natural gas pipeline in south Louisiana, the Cameron Interstate Pipeline, which links the Cameron LNG Phase 1 facility in Cameron Parish in Louisiana, to five interstate pipelines that offer access to major feed gas supply basins in Texas and the northeast, midcontinent and southeast regions of the U.S. The
majority of transportation capacity on the Cameron Interstate Pipeline is under long-term transportation service agreements with shippers for delivery to the Cameron LNG Phase 1 facility.
Natural Gas Distribution. Sempra Infrastructure’s natural gas distribution regulated utility, Ecogas, operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. At December 31, 2022, Ecogas had approximately 2,952 miles of distribution pipeline, and approximately 150,000 customer meters serving more than 525,000 residential,
commercial and industrial consumers with sales volume of approximately 10 MMcf per day in 2022. Ecogas relies on supply and transportation services from Sempra Infrastructure, SoCalGas and PEMEX for the natural gas it distributes to its customers.
LPG Storage and Associated Systems. Sempra Infrastructure owns and operates the TDF, S. de R. L. de C. V. (TDF) pipeline system and the Guadalajara LPG terminal. At December 31, 2022, the TDF pipeline system consisted of approximately 118 miles of 12-inch diameter LPG pipeline with a design capacity of 34,000 barrels per day and associated storage and dispatch facilities. The TDF pipeline system runs from PEMEX’s
Burgos facility in the Mexican State of Tamaulipas, Mexico to Sempra Infrastructure’s delivery facility near the city of Monterrey, Mexico and is fully contracted to PEMEX on a firm basis through 2027. Sempra Infrastructure’s Guadalajara LPG terminal is an 80,000-barrel LPG storage facility near Guadalajara, Mexico, with associated loading and dispatch facilities, and serves the LPG needs of Guadalajara. The Guadalajara LPG terminal is fully contracted to PEMEX on a firm basis through 2028. Both contracts are U.S. dollar-denominated or referenced and are periodically adjusted for inflation.
Refined Products Storage. Sempra Infrastructure’s refined products storage business develops, constructs and operates systems for the receipt, storage and delivery of refined products, principally gasoline, diesel and jet fuel, throughout the Mexican states of Baja California, Colima, Puebla, Sinaloa, Veracruz and
Valle de México for private companies, with a combined storage capacity of 4.6 million barrels fully operating or under construction/commissioning as of December 31, 2022. The inland terminal in the vicinity of Puebla reached commercial operations in October 2022. Construction of the Topolobampo marine terminal was substantially completed in May 2022, at which time commissioning activities commenced. Subject to the receipt of pending permits, we expect the Topolobampo terminal will commence commercial operations in the first half of 2023. Our customer contracts for our refined products storage business are structured as long-term, U.S. dollar-denominated, firm capacity storage agreements with counterparties including Chevron Corporation, Marathon Petroleum Corporation and Valero Energy Corporation. The contracted rate under these contracts is independent from each terminal’s regulated rate as determined by the CRE.
Demand
and Competition. Ecogas faces competition from other distributors of natural gas in each of its three distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico as other distributors of natural gas build or consider building natural gas distribution systems. Sempra Infrastructure’s pipeline and storage facilities businesses compete with other regulated and unregulated pipeline and storage facilities. They compete primarily on the basis of price (in terms of storage and transportation fees), available capacity and interconnections to downstream markets. The overall demand for natural gas distribution services increases during the winter months, while the overall demand for power increases during the summer months.
Clean Power
Sempra Infrastructure’s Clean Power business line consists of a renewable energy infrastructure portfolio and a natural
gas-fired power plant in Mexico.
Renewable Power Generation. Sempra Infrastructure develops, builds, invests in and operates renewable energy generation facilities that have long-term PPAs to sell the electricity they generate to their customers, which are generally load serving entities, as well as industrial and other customers. Load serving entities sell electric service to their end-users and wholesale customers upon receipt of power delivery from these energy generation facilities, while industrial and other customers consume the electricity to run their facilities. At December 31, 2022, Sempra Infrastructure had a fully contracted, total nameplate capacity of 1,044 MW related to its fully operating wind and solar power generation facilities. Some of these facilities are impacted by regulatory actions by the Mexican government and related litigation,
which we discuss in Note 16 of the Notes to Consolidated Financial Statements, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.”
SEMPRA
INFRASTRUCTURE – RENEWABLE POWER GENERATION
Location
Contract expiration date
Nameplate capacity (MW)
Wind power generation facilities:
ESJ – first phase
Tecate, Baja California
2035
155
ESJ
– second phase(1)
Tecate, Baja California
2042
108
Ventika
Nuevo León, Mexico
2036
252
Solar power generation facilities:
Border Solar
Ciudad Juarez, Chihuahua
2032
and 2037
150
Don Diego Solar
Benjamin Hill, Sonora
2034 and 2037
125
Pima Solar
Caborca, Sonora
2038
110
Rumorosa Solar
Tecate, Baja California
2034
44
Tepezalá
Solar
Aguascalientes
2034
100
Total
1,044
(1) Commenced commercial operations in January 2022.
Natural Gas-Fired Generation. Sempra Infrastructure owns and operates the TdM power plant in the vicinity of Mexicali, Baja California, adjacent to the Mexico-U.S. border. TdM is a 625-MW natural gas-fired, combined-cycle power plant that is connected to our Gasoducto Rosarito pipeline system, which enables it to
receive regasified LNG from the ECA Regas Facility as well as continental gas supplied from the U.S. on the North Baja pipeline. TdM generates revenue from selling electricity and resource adequacy to the California ISO and to governmental, public utility and wholesale power marketing entities.
Demand and Competition. Sempra Infrastructure competes with Mexican and foreign companies for new energy infrastructure projects in Mexico. Some of its competitors (including public or state-operated companies and their affiliates) may have better access to capital and greater financial and other resources, which could give them a competitive advantage for such projects.
Generation from Sempra Infrastructure’s renewable energy assets is susceptible to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight. Because Sempra Infrastructure
sells power that it generates at its ESJ wind power generation facility into California, Sempra Infrastructure’s future performance and the demand for renewable energy may be impacted by U.S. state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements in California are generally known as the RPS Program. In California, certification of a generation project by the CEC as an ERR allows the purchase of output from such generation facility to be counted towards fulfillment of the RPS Program requirements, if such purchase meets the provisions of SB X1-2, the California Renewable Energy Resources Act. The RPS Program may affect the demand for output from renewable energy projects developed by Sempra Infrastructure, particularly the demand from California’s utilities. The first phase of ESJ, a wind power generation facility that delivers energy into California, has been certified by the CEC and
is in compliance with the RPS Program as of December 31, 2022. Sempra Infrastructure is pursuing ERR certification for the second phase of ESJ.
TdM competes daily with other generating plants that supply power into the California electricity market. Sempra Infrastructure manages commodity price risk at TdM by using a mix of day ahead sales of energy, energy spreads hedging, ancillary services, and short-term to medium-term capacity sales.
Discontinued Operations
We completed the sales of our equity interests in our Peruvian businesses in April 2020 and our Chilean businesses in June 2020. These South American businesses included our former 100% interest in Chilquinta Energía
(an electric distribution utility in Chile), our former 83.6% interest in Luz del Sur (an electric distribution utility in Peru) and our former interests in two energy-services companies, Tecnored and Tecsur, which provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, respectively, as well as third parties. These businesses and certain activities associated with these businesses are presented as discontinued operations in this report. We provide further information about discontinued operations in Note 5 of the Notes to Consolidated Financial Statements.
REGULATION
We discuss the material effects of compliance with all government regulations, including environmental regulations, on
our capital expenditures, earnings and competitive position in “Part II – Item 7. MD&A” and Note 16 of the Notes to Consolidated Financial Statements.
SDG&E and SoCalGas are principally regulated at the state level by the CPUC, CEC and CARB.
The CPUC:
▪consists
of five commissioners appointed by the Governor of California for staggered, six-year terms;
▪regulates, among other things, SDG&E’s and SoCalGas’ customer rates and conditions of service, sales of securities, rates of return, capital structure, rates of depreciation, and long-term resource procurement, except as described below in “U.S. Federal;”
▪has jurisdiction over the proposed construction of major new electric generation, transmission and distribution, and natural gas storage, transmission and distribution facilities in California;
▪conducts reviews and audits of utility performance and compliance with regulatory guidelines and conducts investigations related to various matters, such as safety, reliability and planning, deregulation,
competition and the environment; and
▪regulates the interactions and transactions of SDG&E and SoCalGas with Sempra and its other affiliates.
The CPUC also oversees and regulates other energy-related products and services, including solar and wind energy, bioenergy, alternative energy storage and other forms of renewable energy. In addition, the CPUC’s safety and enforcement role includes inspections, investigations and penalty and citation processes for safety and other violations.
The CEC publishes electric demand forecasts for the state and specific service territories. Based on these forecasts, the CEC:
▪determines the need for additional energy sources and conservation programs;
▪sponsors
alternative-energy research and development projects;
▪promotes energy conservation programs to reduce demand for natural gas and electricity within California;
▪maintains a statewide plan of action in case of energy shortages; and
▪certifies power-plant sites and related facilities within California.
The CEC conducts a 20-year forecast of available supplies and prices for every market sector that consumes natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and transportation and distribution costs. This analysis is one of many resource materials used to support SDG&E’s and SoCalGas’ long-term investment decisions.
California
requires certain electric retail sellers, including SDG&E, to deliver a significant percentage of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by the CPUC and the CEC, are generally known as the RPS Program. California has implemented a program whereby IOUs providing gas service in California will procure a portion of the natural gas they deliver from biomethane. The proportion of biomethane procured will be phased-in with a state-wide, short-term target in 2025 of 17.6 Bcf per year and a medium-term target in 2030 of 72.8 Bcf per year. SDG&E and SoCalGas are allocated 6.77% and 49.26%, respectively, of the 2025 target, and 7.60% and 52.02%, respectively, of the 2030 target. The rules governing this program are administered by the CPUC under SB 1440.
AB 32, the California Global Warming Solutions Act of 2006, assigns responsibility to CARB for monitoring
and establishing policies for reducing GHG emissions. The law requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable and cost-effective GHG emissions reductions, including a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a department within the California Environmental Protection Agency, an organization that reports directly to the Governor’s Office. Sempra Infrastructure is also subject to the rules and regulations of CARB.
The California Geologic Energy Management Division, the CPUC, and various other state and local agencies regulate the operation and maintenance of SoCalGas’ natural gas storage facilities.
Texas
Oncor’s and Sharyland Utilities’ rates are regulated at the state level by the PUCT and, in the
case of Oncor, at the city level by certain cities. The PUCT has original jurisdiction over wholesale transmission rates and services and retail rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT, and has exclusive appellate jurisdiction to review the retail rate and service orders and ordinances of municipalities. Generally, the Texas PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that do not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).
At
the state level, PURA requires utility owners or operators of electric transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state open-access requirements for all utilities that are subject to the PUCT’s jurisdiction over electric transmission services, including Oncor.
U.S. Federal
SDG&E and SoCalGas are also regulated at the federal level by the FERC, the EPA, the DOE and the DOT, and for SDG&E the NRC.
The FERC regulates SDG&E’s and SoCalGas’ interstate sale and transportation of natural gas. The FERC also regulates SDG&E’s transmission and wholesale sales of electricity in interstate commerce, transmission access,
rates of return on transmission investment, rates of depreciation, electric rates involving sales for resale and the application of the uniform system of accounts. The U.S. Energy Policy Act governs procedures for requests for electric transmission service. The California IOUs’ electric transmission facilities are under the operational control of the California ISO. As member utilities, Oncor and Sharyland Utilities operate within the ERCOT market, which we discuss below. To a small degree related to limited interconnections to other markets, Oncor’s electric transmission revenues are provided under tariffs approved by the FERC.
The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities in the U.S., including SONGS, in which SDG&E owns a 20% interest and which was permanently retired in 2013. The NRC and various state regulations require extensive review of these facilities’ safety,
radiological and environmental aspects. We provide further discussion of SONGS matters, including the closure and decommissioning of the facility, in Note 15 of the Notes to Consolidated Financial Statements.
The EPA implements federal laws to protect human health and the environment, including federal laws on air quality, water quality, wastewater discharge, solid waste management, and hazardous waste disposal and remediation. The EPA also sets national environmental standards that state and tribal governments implement through their regulations. As a result, SDG&E, SoCalGas, Oncor and Sharyland Utilities are subject to an interrelated framework of environmental laws and regulations.
The DOT, through PHMSA, has established regulations regarding engineering standards and operating procedures, including procedures intended to manage cybersecurity risks, applicable to SDG&E’s
and SoCalGas’ natural gas transmission and distribution pipelines, as well as natural gas storage facilities. The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities they regulate in California.
ERCOT Market
As member utilities, Oncor and Sharyland Utilities operate within the ERCOT market, which represents approximately 90% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the ISO of the interconnected transmission grid for those systems. ERCOT is subject to oversight by the PUCT and the Texas Legislature. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants, in the ERCOT region. ERCOT’s membership
consists of corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers, distribution service providers, independent retail electric providers and consumers.
The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected electric transmission grid. Oncor and Sharyland Utilities, along with other owners of electric transmission and distribution facilities in Texas, participate with the ERCOT ISO and other member utilities in its operations. Each of these Texas utilities has planning, design, construction, operation, maintenance and security responsibility for the portion of the transmission grid and the load-serving substations it owns, primarily within its certificated distribution service area. Each participates with the ERCOT
ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove any existing constraints and interconnect energy generation on the ERCOT transmission grid. These transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.
Oncor and Sharyland Utilities are subject to reliability standards adopted and enforced by the Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with the standards of the North American Electric Reliability Corporation, including critical infrastructure protection, and ERCOT protocols.
The South Coast Air Quality Management District is the air pollution control agency responsible for regulating stationary sources of air pollution in the South Coast Air Basin in Southern California. The district’s territory covers all of Orange County and the urban portions of Los Angeles, San Bernardino and Riverside counties.
SDG&E has electric franchise agreements with the two counties and the 27 cities in its electric service territory, and natural gas franchise agreements with the one county and the 18 cities in its natural gas service territory. These franchise agreements allow SDG&E to locate, operate and maintain facilities
for the transmission and distribution of electricity or natural gas. Most of the franchise agreements have no expiration dates, while some have expiration dates that range from 2028 to 2041. In June 2021, the City of San Diego approved ordinances granting SDG&E the electric and natural gas franchises for the City of San Diego. These franchise agreements provide SDG&E the opportunity to serve the City of San Diego for the next 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewal with a supermajority vote. These franchise agreements went into effect in July 2021.
SoCalGas has natural gas franchise agreements with the 12 counties and the 232 cities in its service territory. These franchise agreements allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the
franchise agreements have no expiration dates, while some have expiration dates that range from 2023 to 2069, including the Los Angeles County franchise, which is scheduled to expire in June 2023.
Other U.S. Regulation
The FERC regulates certain Sempra Infrastructure assets pursuant to the U.S. Federal Power Act and Natural Gas Act, which provide for FERC jurisdiction over, among other things, sales of wholesale power in interstate commerce, transportation of natural gas in interstate commerce, and siting and permitting of LNG facilities.
The FERC may regulate rates and terms of service based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be sufficiently competitive, rates may be market-based. FERC-regulated rates at Sempra Infrastructure are market-based for wholesale electricity sales, cost-based
for the transportation of natural gas, and market-based for the purchase and sale of LNG and natural gas.
Sempra Infrastructure’s investment in Cameron LNG JV is subject to regulations of the DOE regarding the export of LNG. Sempra Infrastructure’s other potential natural gas liquefaction projects would, if completed, be subject to similar regulations.
SDG&E, SoCalGas and businesses in which Sempra Infrastructure invests are subject to the DOT rules and regulations regarding pipeline safety. PHMSA, acting through the Office of Pipeline Safety, is responsible for administering the DOT’s national regulatory program to help ensure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines, including pipelines associated with natural gas storage, and develops regulations and other approaches to risk management to help ensure safety in design, construction,
testing, operation, maintenance and emergency response of pipeline facilities. SDG&E, SoCalGas and Sempra Infrastructure are also subject to regulation by the U.S. Commodity Futures Trading Commission.
Foreign Regulation
Operations and projects in our Sempra Infrastructure segment are subject to regulation by the CRE, ASEA, SENER, the Mexican Ministry of Environment and Natural Resources of Mexico (Secretaría del Medio Ambiente y Recursos Naturales), and other labor and environmental agencies of city, state and federal governments in Mexico. New energy infrastructure projects may also require a favorable opinion from Comisión Federal de Competencia Económica (Mexico’s Competition Commission) in order to be constructed and operated.
Licenses and Permits
Our utilities in California and Texas
obtain numerous permits, authorizations and licenses for, as applicable, the transmission and distribution of natural gas and electricity and the operation and construction of related assets, including electric generation and natural gas storage facilities, some of which may require periodic renewal.
Sempra Infrastructure obtains numerous permits, authorizations and licenses for its electric and natural gas distribution, generation and transmission systems from the local governments where these services are provided. The permits for generation, transportation, storage and distribution operations at Sempra Infrastructure are generally for 30-year terms, with options for renewal under certain regulatory conditions.
Sempra Infrastructure obtains licenses and permits for the construction, operation and expansion of LNG facilities and for the import and export of LNG and natural gas.
Sempra Infrastructure also obtains licenses and permits for the construction and operation of facilities for the receipt, storage and delivery of refined products.
Sempra Infrastructure obtains permits, authorizations and licenses for the construction and operation of natural gas storage facilities and pipelines, and in connection with participation in the wholesale electricity market.
Most of the permits
and licenses associated with Sempra Infrastructure’s construction and operations are for periods generally in alignment with the construction cycle or expected useful life of the asset and in many cases are greater than 20 years.
RATEMAKING MECHANISMS
SempraCalifornia
General Rate Case Proceedings
A CPUC GRC proceeding is designed to set sufficient base rates to allow SDG&E and SoCalGas to recover their reasonable forecasted operating costs and to provide the opportunity to realize their authorized rates of return on their investments. The proceeding generally establishes the test year revenue requirements, which authorizes how much SDG&E and SoCalGas can collect from their customers, and provides for attrition, or annual increases in
revenue requirements, for each year following the test year.
We discuss the GRC in Note 4 of the Notes to Consolidated Financial Statements.
Cost of Capital Proceedings
A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and authorized return on rate base, which is a weighted-average of the authorized returns on debt, preferred equity and common equity (referred to as return on equity or ROE), weighted on a basis consistent with the authorized capital structure. The authorized return on rate base approved by the CPUC is the rate that SDG&E and SoCalGas use to establish customer rates to finance investments in CPUC-regulated electric distribution and generation, natural gas distribution, transmission and storage assets, as well as general plant and information technology systems investments
to support operations.
A cost of capital proceeding also addresses the CCM, which applies in the interim years between required cost of capital applications and considers changes in the cost of capital based on changes in interest rates based on the applicable utility bond index published by Moody’s (the CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). The index applicable to SDG&E and SoCalGas is based on each utility’s credit rating. The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered in each measurement period, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus 1.000% at the end of the measurement period. The CCM, if triggered, would automatically update the authorized cost of debt based on actual costs and update the authorized ROE upward or downward by one-half
of the difference between the CCM benchmark rate and the applicable Moody’s utility bond index. Alternatively, each of SDG&E and SoCalGas are permitted to file a cost of capital application in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole to have its cost of capital determined in lieu of the CCM.
We discuss the cost of capital and CCM in Note 4 of the Notes to Consolidated Financial Statements and in “Part I – Item 1A. Risk Factors.”
Transmission Rate Cases
SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets. The proceeding establishes a ROE and a formulaic rate whereby rates are determined using (i) a base period
of historical costs and a forecast of capital investments, and (ii) a true-up period, similar to balancing account treatment, that is designed to provide earnings equal to SDG&E’s actual cost of service including its authorized return on investment. SDG&E makes annual information filings with the FERC in December to update rates for the following calendar year. SDG&E may also file for ROE incentives that might apply under FERC rules. SDG&E’s debt-to-equity ratio is set annually based on the actual ratio at the end of each year.
Incentive Mechanisms
The CPUC applies certain performance-based measures and incentive mechanisms to all California IOUs, under which SDG&E and SoCalGas have earnings potential above the authorized CPUC base operating margin if they achieve or exceed specific performance and operating goals. Generally, for performance-based measures, if
performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.
The CPUC, and the FERC as it relates to SDG&E, authorize SDG&E and SoCalGas to collect revenue requirements from customers for operating and capital-related costs (depreciation, taxes and return on rate base), including:
▪costs to purchase natural gas and electricity;
▪costs associated with administering public purpose, demand response, and customer energy efficiency programs;
▪other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and
▪costs associated with third-party liability insurance premiums.
Authorized costs are recovered as the commodity or service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded in a subsequent period based on the nature of the balancing account mechanism.
Generally, the revenue recognition criteria for balanced costs billed to customers are met when the costs are incurred. Because these costs are substantially recovered in rates through a balancing account mechanism, changes in these costs are reflected as changes in revenues. The CPUC and the FERC may impose various review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including limitations on the program’s total cost, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in delays or disallowances of recovery from ratepayers.
Sempra Texas Utilities
Rates and Cost Recovery
Oncor’s and Sharyland Utilities’ rates are each regulated at the state level by the PUCT and, in the case of Oncor, at the city level by certain cities, and are subject to regulatory
rate-setting processes and earnings oversight. This regulatory treatment does not provide assurance as to achievement of earnings levels or recovery of actual costs. Instead, their rates are based on an analysis of each utility’s costs and capital structure in a designated test year, as reviewed and approved in regulatory proceedings. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. However, there is no assurance that the PUCT will judge all of the Texas utilities’ costs to have been prudently incurred and therefore fully recoverable. The approved levels of recovery could be significantly less than requested levels. There can also be no assurance that the PUCT will approve other items proposed in any rate proceeding or that the regulatory process in which rates are determined will necessarily result in rates that produce full recovery of the Texas utilities’ actual post-test year costs and/or
the return on invested capital allowed by the PUCT.
PUCT rules allow Texas electric utilities providing wholesale or retail distribution service to file applications, under certain circumstances, once per year to recover distribution-related investments placed into service between base rate review proceedings. PUCT rules also allow the Texas utilities to update their transmission rates twice a year between base rate review proceedings to reflect changes in transmission-related invested capital. These applications for interim rate adjustments between base rate reviews, known as “capital tracker” provisions, are intended to encourage investment in the electric system to help ensure reliability and efficiency by helping to shorten the time period between a utility’s investment in transmission and distribution infrastructure and its ability to start recovering and earning a return on such investments. However, all investments
included in a capital tracker are ultimately subject to prudence review by the PUCT in the next base rate review, after such assets are put into service.
Capital Structure and Return on Equity
Oncor currently has a PUCT-authorized ROE of 9.8% and an authorized regulatory capital structure of 57.5% debt to 42.5% equity. Oncor filed its base rate review request with the PUCT in May 2022. Resolution of the base rate review requires issuance of a final order by the PUCT, which Oncor expects to receive around the end of the first quarter of 2023. Once the final order is issued, the approved rates will be in effect until the next base rate review is finalized. In accordance with PUCT rules, Oncor must file a comprehensive base rate review within four years of the order setting rates in Oncor’s most recent comprehensive base rate proceeding, unless an extension is otherwise approved by
the PUCT. However, the PUCT or any city retaining original jurisdiction over rates may direct Oncor to file a base rate review, or Oncor may voluntarily file a base rate review, any time prior to that filing deadline.
Sharyland Utilities’ 2020 rate case became effective in July 2021 and remains effective until the next rate case is finalized, which we expect could be in late 2025. Sharyland Utilities’ PUCT-authorized ROE is 9.38% and its authorized regulatory capital structure is 60% debt to 40% equity.
Ecogas’ revenues are derived from service and distribution fees charged to its customers in Mexican pesos. The price Ecogas pays to purchase natural gas, which is based on international price indices, is passed through directly to its customers. The service and distribution fees charged by Ecogas are regulated by the CRE, which performs a review of rates every five years and monitors prices charged to end-users. In the fourth quarter of 2020, Ecogas filed its rate case for 2021 through 2025 and is awaiting CRE approval. The tariffs operate under a return-on-asset-base model. In the annual tariff adjustment, rates are adjusted to account for inflation or fluctuations in exchange rates, and inflation indexing includes separate U.S. and Mexican cost components so that U.S. costs can be included in the final distribution rates.
ENVIRONMENTAL
MATTERS
We discuss environmental issues affecting us in Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors.” You should read the following additional information in conjunction with those discussions.
Hazardous Substances
The CPUC’s Hazardous Waste Collaborative mechanism allows California’s IOUs to recover hazardous waste cleanup costs for certain sites, including those related to certain Superfund sites. For sites that are covered by this mechanism, SDG&E and SoCalGas are permitted to recover in rates 90% of hazardous waste cleanup costs and related third-party litigation costs, and 70% of related insurance-litigation expenses. In addition, SDG&E and SoCalGas can retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated
litigation costs not recovered in rates.
We record estimated liabilities for environmental remediation when amounts are probable and estimable. In addition, we record amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism as regulatory assets.
Air and Water Quality
The natural gas and electric industries are subject to increasingly stringent air quality and GHG emissions standards, such as those established by CARB and the South Coast Air Quality Management District. SDG&E and SoCalGas generally recover the costs to comply with these standards in rates. We discuss GHG emissions standards and credits further in Note 1 of the Notes to Consolidated Financial Statements.
Our ability to advance our mission to be North America’s premier energy infrastructure company largely depends on the safety, engagement, and responsible actions of our employees.
Safety is foundational at Sempra and its subsidiaries. We strive to foster a strong safety culture and reinforce this culture through training programs, benchmarking, review and analysis of safety trends, and sharing lessons learned from safety incidents across our businesses. Our businesses also engage in safety-related scenario planning and simulation, develop and implement operational contingency plans, and review safety plans and procedures with work crews regularly. We also participate in
emergency planning and preparedness in the communities we serve and train critical employees in emergency management and response each year. The Safety, Sustainability and Technology committee of the Sempra board of directors assists the board in overseeing the corporation’s oversight programs and performance related to safety, and our executives’ annual incentive compensation is based in part on safety metrics established by the Compensation and Talent Development Committee of the Sempra board of directors.
Our overall culture is another important aspect of our ability to advance our mission. We embrace diversity in our workforce and strive to create a high-performing, inclusive and supportive workplace where employees of all backgrounds and experiences feel valued and respected. We invest in recruiting, developing and retaining high-potential employees who represent the communities we serve, and we provide a range of programs
to advance those objectives, including internal and external mentoring and leadership training and workshops, employee resource groups, and a benefits package including wellness benefits and a tuition reimbursement program. We also invest in internal communications programs, including in-person and virtual learning and networking opportunities as well as regular executive communications to employees on topics of interest. In addition, we offer a variety of employee community service opportunities and, at our U.S. operations, we support employees’ personal volunteering and charitable giving through Sempra’s charitable matching program. Employees participate in annual ethics and compliance training, which includes a review of Sempra’s Code of Business Conduct as well as information about resources such as Sempra’s ethics and compliance helpline. We measure culture and employee engagement through a variety of channels including pulse surveys, suggestion boxes and a biannual
engagement survey administered by a third party.
The table below shows the number of employees for each of our registrants at December 31, 2022, 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 2022 and we maintain constructive relations with our labor unions.
NUMBER
OF EMPLOYEES
Number of employees
% of employees covered under collective bargaining agreements
% of employees covered under collective bargaining agreements expiring within one year
Sempra(1)
15,785
37
%
—
%
SDG&E
4,633
30
%
—
%
SoCalGas
8,460
53
%
—
%
(1) Excludes
employees of equity method investees.
We
make available free of charge on the Sempra website, and for SDG&E and SoCalGas, via a hyperlink on their websites, annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.
The references to our websites in this report are not active hyperlinks and the information contained on, or that can be accessed through, the websites of Sempra, SDG&E and SoCalGas or any other website referenced herein is not a part of or incorporated by reference in this report or any other document that we file with or furnish to the SEC.
When evaluating our company and its subsidiaries and any investment in our or their
securities, you should carefully consider the following risk factors and all other information contained in this report and the other documents we file with the SEC (including those filed subsequent to this report). We also may be materially harmed by risks and uncertainties not currently known to us or that we currently consider immaterial. If any of these risks occurs, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected, our actual results could differ materially from those expressed in any forward-looking statements made by us or on our behalf, and the trading price of our securities and those of our subsidiaries could decline. These risk factors are not prioritized in order of importance or materiality, and they should be read in conjunction with the other information in this report, including the information set forth in the Consolidated Financial Statements and in “Part II – Item 7. MD&A.”
RISKS
RELATED TO SEMPRA
Operational and Structural Risks
Sempra’s cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its subsidiaries and entities accounted for as equity method investments.
We are a holding company and substantially all our assets are owned by our subsidiaries or entities we do not control, including equity method investments. Our ability to pay dividends and meet our debt and other obligations largely depends on cash flows from our subsidiaries and equity method investments, which in turn depend on their ability to execute their business strategies and generate cash flows in excess of their own expenditures, dividend payments to third-party owners (if any) and debt and other obligations. In addition, entities accounted for as equity method investments, which
we do not control, and our subsidiaries are all separate and distinct legal entities that are not obligated to pay dividends or make loans or distributions to us and could be precluded from doing so by legislation, regulation, court order or contractual restrictions, in times of financial distress or in other circumstances. The inability to access capital from our subsidiaries and entities accounted for as equity method investments could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Sempra’s rights to the assets of its subsidiaries and equity method investments are structurally subordinated to the claims of each entity’s trade and other creditors. If Sempra is a creditor of any such entity, its rights as a creditor would be effectively subordinated to any security interest in the entity’s assets and any indebtedness of the entity senior to that held by Sempra.
In addition, Sempra may elect to make capital contributions to its subsidiaries, which are not required to be repaid and generally are structurally subordinated to claims by creditors of the applicable subsidiary.
Sempra has substantial investments in and obligations arising from businesses it does not control or manage or in which it shares control.
We have investments in businesses we do not control or manage or in which we share control. In some cases, we engage in arrangements with or for these businesses that could expose us to risks in addition to our investment, including guarantees, indemnities and loans. For businesses we do not control, we are subject to the decisions of others, which may not always be in our interest and could negatively affect us. When we share control of a business with other owners, any disagreements among the owners about strategy, financial, operational,
transactional or other important matters could hinder the business from moving forward with key initiatives or taking other actions and could negatively affect the relationships among the owners and the efficient functioning of the business. In addition, irrespective of whether or not we control these businesses, we could be responsible for liabilities or losses related to these businesses or elect to make capital contributions to these businesses. Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We discuss these investments in Note 6 of the Notes to Consolidated Financial Statements.
Our business could be negatively affected by activist shareholders.
Activist shareholders may engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes in or assert influence
on our board of directors and management. In taking these steps, activist shareholders could seek to acquire our capital stock, which at certain ownership levels could threaten our ability to use some or all our NOL carryforwards if our corporation experiences an “ownership change” under applicable tax rules. Responding to activist shareholders could require us to
incur legal and advisory fees, proxy solicitation expenses and administrative
and associated costs and require time and attention by our board of directors and management, diverting their attention from the pursuit of our business strategies.
Any perceived uncertainties about our future direction or control, our ability to execute our strategies, or the composition of our board of directors or management team arising from activist shareholder attention or other action could lead to a perception of instability or a change in the direction of our business, which could be exploited by our competitors and/or other activist shareholders, result in the loss of business opportunities, and make it more difficult to pursue our strategic initiatives or attract and retain qualified personnel and business partners, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Further, any such actions could cause fluctuations in the trading prices
of our securities based on temporary or speculative market perceptions or other factors.
Financial and Capital Stock-Related Risks
Any impairment of our assets or investments could negatively impact us.
We could experience a reduction in the fair value of our assets, including our long-lived assets, intangible assets or goodwill, and/or our investments that we account for under the equity method upon the occurrence of many of the risks discussed in these risk factors and elsewhere in this report, including any closure of the Aliso Canyon natural gas storage facility without adequate cost recovery, any inability to operate our existing facilities or develop new projects in Mexico due to proposed changes to existing laws or regulations or other circumstances affecting the energy sector or our assets in that country, and more generally any
loss of permits or approvals that requires us to adjust or cease certain operations and any investment in capital projects that do not receive required approvals or are changed, abandoned or otherwise not completed. Any such reduction in the fair value of our assets or investments could result in an impairment loss that could materially adversely affect our results of operations for the period in which the charge is recorded. We discuss our impairment testing of long-lived assets and goodwill and the factors considered in such testing in “Part II – Item 7. MD&A – Critical Accounting Estimates” and in Note 1 of the Notes to Consolidated Financial Statements.
The economic interest, voting rights and market value of our outstanding common and preferred stock may be adversely affected by any additional equity securities we may issue.
At February 21,
2023, we had 314,569,519 shares of our common stock and 900,000 shares of our non-convertible series C preferred stock outstanding. We may seek to raise capital by issuing additional equity or convertible debt securities, which may materially dilute the voting rights and economic interests of holders of our outstanding common and preferred stock and materially adversely affect the trading price of our common and preferred stock.
Dividend requirements associated with our preferred stock subject us to risks.
Any failure to pay scheduled dividends on our series C preferred stock when due would have a material adverse impact on the market price of our securities and would prohibit us, under the terms of the series C preferred stock, from paying cash dividends on or repurchasing shares of our common stock (subject to limited exceptions) until we have paid all accumulated and unpaid
dividends on the series C preferred stock. Additionally, the terms of the series C preferred stock generally provide that if dividends on any shares of the preferred stock have not been declared and paid or have been declared but not paid for three or more semi-annual dividend periods, whether or not consecutive, the holders of the preferred stock would be entitled to elect two additional members to our board of directors, subject to certain terms and limitations.
Our common stock is listed on the Mexican Stock Exchange and registered with the CNBV, which subjects us to additional regulation and liability in Mexico.
In addition to being listed for trading on the NYSE, our common stock is listed for trading on the Mexican Stock Exchange and registered with the CNBV. Such listing and registration subjects us to filing and other requirements in Mexico that could increase costs and increase
performance risk of personnel given additional responsibilities. In addition, the CNBV, as the Mexican securities market regulator, has the authority to make inspections of Sempra’s business, primarily in the form of requests for information and documents; impose fines or other penalties on Sempra and its directors and officers for violations of Mexican securities laws and regulations; and seek criminal liability for certain actions conducted or with effects in Mexico. The occurrence of any of these risks could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our businesses are subject to risks arising from their infrastructure and information systems.
Our businesses’ facilities and the information systems that interconnect and/or manage them are subject to risks of, among other things, potential breakdown or failure of equipment or processes due to aging infrastructure and systems; human error; shortages of or delays in obtaining equipment, materials, commodities or labor, which may be exacerbated by current or future supply chain constraints and tight labor market conditions, and increases to the costs of these items due to inflationary pressures or otherwise, which may not be recoverable in a timely manner or at all; operational restrictions resulting from environmental requirements or governmental interventions; inability to enter into,
maintain, extend or replace long-term supply or transportation contracts; and performance below expected levels. Even though our businesses undertake capital investment projects to construct, replace, maintain, improve and upgrade facilities and systems, such projects may not be effective at managing the aforementioned risks, and may involve significant costs that may not be recoverable and challenges in achieving completion. We often rely on third parties, including contractors, to perform work related to these projects and other maintenance activities, which may subject us to increased risks because we manage the safety and quality of work performed by third parties and may retain liability for their work. Because our facilities are interconnected with those of third parties, including receiving natural gas supply from third party pipelines and power generation facilities that produce most of the power that we distribute to customers, the operation of our facilities
could also be adversely affected by these or similar risks to the systems of such third parties, many of which may be unanticipated or uncontrollable by us.
Additional risks associated with our businesses’ ability to safely and reliably construct, replace, operate, maintain, improve and upgrade their respective facilities and systems, many of which are beyond our control, include:
▪failure to meet customer demand for electricity and/or natural gas, including electrical blackouts or curtailments or gas outages
▪natural gas surges into homes or other properties
▪the release of hazardous or toxic substances, including gas leaks
▪inadequate
emergency preparedness plans and the failure to respond effectively to catastrophic events
The occurrence of any of these events could affect supply and demand for electricity, natural gas or other forms of energy, cause unplanned outages, damage our businesses’ assets and/or operations, damage the assets and/or operations of third parties on which our businesses rely, damage property owned by customers or others, and cause personal injury or death. In addition, if we are unable to defend and retain title to the properties we own or if we are unable to obtain or retain rights to construct and operate on the properties we do not own in a timely manner, on reasonable terms or at all, we could lose our rights to occupy and use these properties and the related facilities, which could result in modification, delay or curtailment of existing or proposed operations or projects, increase our costs, and result in breaches of one or
more permits or contracts related to the affected facilities that could lead to legal costs, impairments or fines or penalties. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Severe weather, natural disasters and other similar events could materially adversely affect us.
Our facilities and infrastructure, including projects in development and under construction, may be damaged by severe weather, natural disasters, accidents, explosions or acts of terrorism, war or criminality. Because we are in the business of using, storing, transporting and disposing of highly flammable, explosive and radioactive materials and operating highly energized equipment, the risks such incidents may pose to our facilities and infrastructure, as well as the risks to the surrounding communities for which we could be held
responsible, are substantially greater than the risks such incidents pose to a typical business.
Such incidents could result in business and project development disruptions, power or gas outages, property damage, injuries and loss of life for which we could be liable and could cause secondary incidents that also may have these or other negative effects, such as fires; leaks of natural gas, natural gas odorant, propane, ethane, other GHG emissions or radioactive material; spills or other damage to natural resources; or other nuisances to affected communities. Any of these occurrences could decrease revenues and earnings and/or increase costs, including maintenance costs or restoration expenses, amounts associated with claims against us, and regulatory fines, penalties and disallowances. In some cases, we may be liable for damages even though we are not at fault, such as when the doctrine of inverse condemnation applies, which
we discuss below under “Risks Related to Sempra California – Operational Risks.” For our regulated utilities, these costs may not be recoverable in rates. Insurance coverage for these costs may increase or become prohibitively expensive, be disputed by insurers, or become unavailable for certain of these risks or at sufficient levels, and any insurance proceeds may be insufficient to cover our losses or liabilities due to limitations, exclusions, high deductibles, failure to comply with procedural requirements or other factors. Such incidents that do not directly
affect
our facilities may impact our business partners, supply chains and transportation channels, which could negatively impact construction projects and our ability to provide electricity and natural gas to customers. Moreover, weather-related incidents have become more prevalent, unpredictable and severe as a result of climate change or other factors, which could have a greater impact on our businesses than currently anticipated and, for our regulated utilities, rates may not be adequately or timely adjusted to reflect any such increased impact. Any such outcome could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
In addition to general information and cyber risks that all large corporations face, we face evolving cybersecurity risks associated with the energy grid, natural gas pipelines, storage and other infrastructure and protecting sensitive and confidential customer
and employee information.
Our use of complex technologies and systems in our operations, including deployment of any new technologies, and our collection and retention of sensitive information, represent large-scale opportunities for attacks on or other failures to protect our information systems, confidential information and energy grid and natural gas infrastructure. In particular, cyber-attacks targeting utility systems and other energy infrastructure, as well as the impacts of these attacks on companies and their communities, are increasing in sophistication, magnitude and frequency and may further increase in connection with certain geopolitical events, such as the war in Ukraine. Additionally, SDG&E and SoCalGas are increasingly required to disclose large amounts of data (including customer personal information and energy use data) to support changes to California’s electricity and gas markets related to grid modernization
and customer choice as well as energy efficiency, demand response and conservation, increasing the risks of inadvertent disclosure or other unauthorized access of sensitive information. Further, the virtualization of many business activities increases cyber risk, and generally there has been an associated increase in targeted cyber-attacks. Moreover, all our businesses operating in California (and any other states and countries where we do business that adopt similar laws) are subject to enhanced state privacy laws, which require companies that collect information about California residents to, among other things, make disclosures to consumers about their data collection, use and sharing practices; allow consumers to opt out of certain data sharing with third parties; and assume liability under a new cause of action for unauthorized disclosure of certain highly sensitive personal information.
Although we invest in risk management
and information security measures for the protection of our systems and information, these measures could be insufficient or otherwise fail. The costs and operational consequences of implementing, maintaining and enhancing these protection measures are significant, and they could materially increase to address increasingly intense and complex cyber risks. We often rely on third-party vendors to deploy new business technologies and maintain, modify and update our systems, and these third parties may not have adequate risk management and information security measures with respect to their systems. Any cyber-attack, including ransomware attacks, on our or our vendors’ information systems or the integrity of the energy grid, our pipelines or our distribution, storage and other infrastructure, or unauthorized access, damage or improper disclosure of confidential information, could result in disruptions to our business operations, regulatory compliance failures, inabilities
to produce accurate and timely financial statements, energy delivery failures, financial and reputational loss, customer dissatisfaction, litigation, violation of privacy laws and fines or penalties, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Although Sempra currently maintains cyber liability insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover any or even a substantial portion of the costs associated with any compromise of our information systems or confidential information, and there is no guarantee that the insurance we currently maintain will continue to be available at rates we believe are commercially reasonable.
We seek growth opportunities in the market organically and inorganically, including through the acquisition of, or partnerships in, operating companies.
We
diligently analyze the financial viability of each acquisition, partnership and JV we pursue. However, our diligence may prove to be insufficient and there could be latent, unforeseen defects. In addition, we may not realize all the anticipated benefits from future acquisitions, partnerships or JVs for various reasons, including difficulties integrating operations and personnel to our standards or in a timely manner, higher and unexpected acquisition and operating costs, unknown liabilities, and fluctuations in markets. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Increasing activities and projects intended to advance new energy technologies could introduce new risks to our businesses.
We regularly undertake or become involved in research and development projects and other activities designed
to develop new technologies in the energy space, including those related to hydrogen, energy storage, carbon sequestration, grid modernization and others. These activities and projects can involve significant employee time, as well as substantial capital resources that may
not be recoverable in rates or, with respect to our non-regulated utility businesses, may not be able to be passed through to customers. We may also seek a variety of federal and
state funding opportunities for these activities and projects (such as loans and grants, including in conjunction with third-party commercial or governmental entities), which may involve significant employee time and effort and increased compliance requirements with no guarantee that any such funding would be received. In addition, the timing to complete these activities and projects is inherently uncertain and may require significantly more time and funding than we initially anticipate. Moreover, many of these technologies are in the early stage of development, and the applicable activities and projects may not be completed or the applicable technologies may not prove economically and technically feasible. If any of these circumstances occurs, we may not receive an adequate or any return on our investment and other resources invested in these activities and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
The
operation of our facilities depends on good labor relations with our employees.
Several of our businesses have in place collective bargaining agreements with different labor unions, which are generally negotiated on a company-by-company basis. Any failure to negotiate and reach an agreement on these labor contracts as they are up for renewal could result in strikes, boycotts or other labor disruptions. Any such labor disruption or negotiated wage or benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Our businesses depend on the performance of counterparties, and any performance failures by these counterparties could materially adversely affect us.
Our businesses depend on the performance of
business partners, customers, suppliers and other counterparties who owe money or commodities as a result of market transactions or other long-term arrangements. If they fail to perform their obligations in accordance with these arrangements, we may need to enter into alternative arrangements or honor our underlying commitments at then-current market prices, which may result in additional losses to us to the extent of amounts already paid to such counterparties. Any efforts to enforce the terms of these arrangements through legal or other means could involve significant time and costs and would be unpredictable and may not be successful. In addition, many of these arrangements, including our relationships with the applicable counterparties, are important for the conduct and growth of our businesses. We also may not be able to secure replacement agreements with other counterparties on favorable terms, in a timely manner or at all if any of these arrangements terminate.
Further, we often extend credit to customers and other counterparties and, although we perform credit analyses prior to extending credit, we may not be able to collect the amounts owed to us, which presents an increased risk for our long-term supply, sales and capacity contracts. The failure of any of our counterparties to perform in accordance with their arrangements with us could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Sempra Infrastructure’s obligations and those of its LNG suppliers are contractually subject to suspension or termination for force majeure events, which generally are beyond the control of the parties, and limitations of remedies for other failures to perform, including limitations on damages that may prohibit recovery of costs incurred for any breach of an agreement. Any such occurrence could have a material adverse effect on our results of
operations, financial condition, cash flows and/or prospects.
Sempra Infrastructure engages in JVs and invests in companies in which other equity partners may have or share with us control over the applicable project or investment. Sempra Texas Utilities also invests in companies that it does not control or manage. We discuss the risks related to these arrangements above under “Risks Related to Sempra – Operational and Structural Risks.”
Our businesses face risks related to the COVID-19 pandemic.
The COVID-19 pandemic has materially impacted communities, supply chains, economies and markets around the world since March 2020. To date, the COVID-19 pandemic has not had a material impact on our results of operations. However, Sempra and some or all its businesses have been and could continue to be impacted by this pandemic or any future
pandemic in a number of ways, including:
▪Disruption in supply chains and the capital markets, which has affected and could further affect liquidity, strategic initiatives and prospects, including in some cases a slowdown of planned capital spending
▪Customer-protection measures implemented by SDG&E and SoCalGas, including suspending service disconnections due to nonpayment for all customers early in the pandemic (except for SoCalGas’ noncore customers and, since the second half of 2022, SDG&E’s and SoCalGas’ commercial and industrial customers), waiving late payment fees, offering flexible payment plans and automatically enrolling residential and small business customers with past-due balances in long-term repayment plans, which have collectively resulted in a reduction in payments from SDG&E and SoCalGas’
customers and an increase in uncollectible accounts that could become material and may not be fully recoverable
▪Precautionary, preemptive and responsive actions taken by our current and prospective counterparties, customers and partners, as well as regulators and other governing bodies that affect our businesses, which have affected and could further affect our operations, results, liquidity and ability to pursue capital
projects and strategic initiatives
Any of these impacts could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. We will continue to actively monitor the effects of the COVID-19 pandemic and may take further actions that alter our business operations as may be required by federal, state or local authorities, or that we determine are necessary for the safety of our employees, customers, partners and suppliers and, generally, the communities we serve. However, we cannot at this time predict the extent to which the COVID-19 pandemic may further impact our businesses.
Financial Risks
Our debt service obligations expose us to risks and could require additional equity securities issuances by Sempra and sales of equity interests in various subsidiaries or projects under development.
Our
businesses have debt service obligations, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects by, among other things:
▪making it more difficult and costly for each of these businesses to service, pay or refinance their debts as they come due, particularly during adverse economic or industry conditions or in periods of significant increases in interest rates
▪limiting flexibility to pursue strategic opportunities or react to business developments or changes in the industry sectors in which they operate
▪requiring cash to be used for debt service payments, thereby reducing the cash available for other purposes
▪causing
lenders to require materially adverse terms in the instruments for new debt, such as restrictions on uses of proceeds or other assets or limitations on incurring additional debt, creating liens, paying dividends, repurchasing stock, making investments or receiving distributions from subsidiaries or equity method investments
Sempra’s goal is to maintain or improve its credit ratings, but it may not be able to do so. To maintain these credit ratings, we may seek to reduce our outstanding indebtedness or our need for additional indebtedness with the proceeds from issuances of equity securities by Sempra or the sale of equity interests in our subsidiaries or development projects. We may not be able to complete any such equity sales on terms we consider acceptable or at all, and any new equity issued by Sempra may dilute the voting rights and economic interests of existing holders of Sempra’s common and preferred stock. Any such
outcome could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.
The availability and cost of debt or equity financing could be negatively affected by market and economic conditions and other factors, and any such effects could materially adversely affect us.
Our businesses are capital-intensive, with significant capital spending expected in future periods. In general, we rely on long-term debt to fund a significant portion of our capital expenditures and repay outstanding debt and we rely on short-term borrowings to fund a significant portion of day-to-day business operations. Sempra may also seek to raise capital by issuing equity or selling equity interests in our subsidiaries or investments.
Limitations on the availability of credit, increases in
interest rates or credit spreads due to inflationary pressures or otherwise or other negative effects on the terms of any financing we pursue could cause us to fund operations and capital expenditures at a higher cost or fail to raise our targeted amount of funding, which could negatively impact our ability to meet contractual and other commitments, progress development projects, make non-safety related capital expenditures and effectively sustain operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
In addition to market and economic conditions, factors that can affect the availability and cost of capital include:
▪adverse changes to laws and regulations, including recent and proposed changes to the regulation of the energy market in Mexico
▪the
overall health of the energy industry
▪volatility in electricity or natural gas prices
▪for Sempra, SDG&E and SoCalGas, risks related to California wildfires
▪for Sempra, SDG&E and SoCalGas, any deterioration of or uncertainty in the political or regulatory environment for local natural gas distribution companies operating in California
We are subject to risks due to uncertainty relating to the calculation of LIBOR and its scheduled discontinuance.
Certain of our financial and commercial agreements, including those for variable rate indebtedness, as well as interest rate derivatives, incorporate LIBOR as a benchmark for establishing certain rates. As directed by the U.S. Federal Reserve, banks ceased making new LIBOR-based issuances at the end of 2021, and publication of certain key U.S. dollar LIBOR tenors for existing loans is expected to cease in mid-2023. These events could cause LIBOR to perform differently than it has performed historically. Use of the SOFR, which has been identified as the replacement benchmark rate for LIBOR, may result in interest payments
that are higher than expected or that do not otherwise correlate over time with the payments that would have been made using LIBOR. Changes to or the discontinuance of LIBOR, any uncertainty regarding such changes or discontinuance, and the performance and characteristics of alternative benchmark rates, could negatively affect our existing and future variable rate indebtedness and interest rate hedges and the cost of doing business under our commercial agreements that incorporate LIBOR, SOFR or other alternative benchmark rates, and could require us to seek to amend the terms of the relevant indebtedness or agreements, which may not be possible and/or may require us to accept terms that are materially worse than existing terms. The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Credit rating agencies may downgrade our credit
ratings or place those ratings on negative outlook.
Credit rating agencies routinely evaluate Sempra, SDG&E, SoCalGas and SI Partners and certain of our other businesses, and their ratings are based on a number of factors, including the factors described below and the ability to generate cash flows; level of indebtedness; overall financial strength; specific transactions or events, such as share repurchases and significant litigation; the status of certain capital projects; and the state of the economy and our industry generally. These credit ratings could be downgraded or other negative credit rating actions could occur at any time. We discuss these credit ratings in “Part II – Item 7. MD&A – Capital Resources and Liquidity.”
For Sempra, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:
▪expansion
of natural gas liquefaction projects or other unregulated businesses in a manner inconsistent with its present level of credit quality
▪Sempra’s consolidated financial measures do not improve, or it fails to meet certain financial credit metrics
▪catastrophic wildfires caused by SDG&E or by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably earlier than expected
For SDG&E, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:
▪catastrophic wildfires caused by SDG&E or by any California electric IOUs that participate in the Wildfire Fund, which could exhaust the fund considerably
earlier than expected
▪a consistent weakening of SDG&E’s financial metrics or a deterioration in the regulatory environment
▪a ratings downgrade at Sempra
For SoCalGas, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:
▪SoCalGas’ financial measures consistently weaken, or it fails to meet certain financial credit metrics
▪SoCalGas experiences increased business risk, including a deterioration in the regulatory environment, leading to weakening of its stand-alone business risk profile
▪a ratings
downgrade at Sempra
For SI Partners, the Rating Agencies have noted that the following events, among others, could lead to negative ratings actions:
▪SI Partners’ failure to meet certain financial credit metrics
▪a deterioration in SI Partners’ business risk profile, including incremental construction risk or adverse changes in the operating environment in Mexico
▪a ratings downgrade at Sempra, IEnova and/or Cameron LNG, LLC
A downgrade of any of our businesses’ credit ratings or ratings outlooks, as well as the reasons for such downgrades, may materially adversely affect the market prices of our securities, the interest rates at which borrowings can be made
and debt securities issued, and the various fees on our credit facilities. This could make it more costly for the affected businesses to borrow money, issue securities and/or raise other types of capital, any of which could materially adversely affect our ability to meet our debt obligations and contractual commitments, and our results of operations, financial condition, cash flows and/or prospects.
We do not fully hedge our assets or contract positions
against changes in commodity prices or interest rates, and for those positions that are hedged, our hedging procedures may not mitigate our risk as expected or prevent us from experiencing losses.
We have used and may continue to use forward contracts, futures, financial swaps and/or options, among other mechanisms, 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 in an effort to reduce our financial exposure related to commodity price fluctuations. We do not hedge the entire exposure to market price volatility of our assets or our contract positions, and the extent of the coverage to these exposures varies over time. In addition, we have used and may continue to use similar financial instruments to hedge against changes in interest rates. Certain derivative securities we use to hedge are recorded at
fair value through earnings to reflect movements in the price of the security, which has in the past and could in the future create volatility in our earnings (such as the significantly higher unrealized losses on commodity derivatives that we recognized in 2022 compared to 2021 as we discuss in “Part II – Item 7. MD&A – Results of Operations”). To the extent we have unhedged positions, or if our hedging strategies do not work as expected, fluctuating commodity prices could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Certain of the contracts we may use for hedging purposes are subject to fair value accounting, which may result in gains or losses in earnings for those contracts that may not reflect the associated gains or losses of the underlying position being hedged and could result in fluctuations of our results from period to period.
Risk management
procedures may not prevent or mitigate losses.
Although we have in place risk management and control systems designed to quantify and manage risk, these systems may not prevent material losses. Risk management procedures may not always be followed as intended or function as expected. In addition, daily VaR and loss limits, which are primarily based on historic price movements and which we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” may not protect us from losses if prices significantly or persistently deviate from historic prices. As a result of these and other factors, our risk management procedures and systems may not prevent or mitigate losses that could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Market performance or changes in other assumptions could require unplanned
contributions to pension and PBOP plans.
Sempra, SDG&E and SoCalGas provide defined benefit pension and PBOP plans to eligible employees and retirees. The cost of providing these benefits is affected by many factors, including the market value of plan assets and the other factors described in Note 9 of the Notes to Consolidated Financial Statements. A decline in the market value of plan assets or an adverse change in any of these other factors could cause a material increase in our funding obligations for these plans, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Legal and Regulatory Risks
Our businesses require numerous permits, licenses, franchises and other approvals from various governmental agencies, and the failure to obtain or maintain any of them,
or lengthy delays in obtaining them, could materially adversely affect us.
Our businesses require numerous permits, licenses, rights-of-way, franchises, certificates and other approvals from federal, state, local and foreign governmental agencies. These approvals may not be granted in a timely manner or at all or may be modified, rescinded or fail to be extended for a variety of reasons. Obtaining or maintaining these approvals could result in higher costs or the imposition of conditions or restrictions on our operations. For example, SoCalGas’ franchise agreement with Los Angeles County is scheduled to expire in June 2023. Further, these approvals require compliance by us and may require compliance by our customers, which could result in modification, suspension or rescission and subject us to fines and penalties in the event of noncompliance. If one or more of these approvals were to be suspended, rescinded or otherwise terminated,
including due to expiration or legal or regulatory changes, or modified in a manner that makes our continued operation of the applicable business prohibitively expensive or otherwise undesirable or impossible, we may be required to adjust or temporarily or permanently cease certain of our operations, sell the associated assets or remove them from service and/or construct new assets intended to bypass the impacted area, in which case we may lose some of our rate base or revenue-generating assets, our development projects may be negatively affected and we may incur impairment charges or other costs that may not be recoverable. The occurrence of any of these events could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We may invest funds in capital projects prior to receiving all regulatory approvals. If there is a delay in obtaining these approvals; if any approval is conditioned
on changes or other requirements that increase costs or impose restrictions on our existing or
planned operations; if we fail to obtain or maintain these approvals or comply with them or other applicable laws or regulations; if we are involved in litigation that adversely impacts any approval or rights to the applicable property or assets; or if management decides not to proceed with a project, we may be unable to recover any or all amounts invested
in that project. Any such occurrence could cause our costs to materially increase, result in material impairments, and otherwise materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our businesses face climate change concerns and have environmental compliance and clean energy transition costs, which could have a material adverse effect on us.
Climate change and the costs associated with its impacts and mitigation may have the potential to adversely affect our businesses, including by increasing the costs we incur to transmit energy and provide other services, impacting the demand for and consumption of the natural gas we distribute and the energy we transmit (due to changes in costs, weather patterns, the type of energy transmitted as a result of increasing customer preference for carbon-neutral and renewable
sources of energy, and other factors), and affecting the economic health of the regions in which we operate.
Our businesses are subject to extensive federal, state, local and foreign statutes, orders, rules and regulations relating to climate change and environmental protection. To comply with these requirements, we must expend significant capital and employee resources on (i) environmental monitoring, surveillance and other measures to track performance; (ii) acquisitions of pollution control equipment; (iii) mitigation efforts; and (iv) emissions fees, which could increase as a result of various factors we may not control, including changing laws and regulations, increased enforcement activities, delays in the renewal and issuance of permits, and changes to the mix of energy we are required to supply. In addition, we are generally responsible for hazardous substances and other contamination on and the conditions of our projects
and properties, regardless of when these conditions arose and whether they are known or unknown. In addition, we could be liable for contamination at our former facilities and off-site waste disposal sites that have been used in our operations. For our regulated utilities, some of these costs may not be recoverable in rates. Failure to comply with environmental laws and regulations may subject our businesses to fines and penalties, including criminal penalties in some cases, and/or curtailment of our operations. Any of these outcomes could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Increasing international, national, regional, state and local-level environmental concerns and related new or proposed legislation and regulation or changes to existing legislation or regulation, such as increased requirements for monitoring and surveillance, disclosures on environmental
performance and targets, pollution monitoring and control equipment, safety practices, emissions fees, taxes, penalties or other obligations or restrictions, may have material negative effects on our operations, operating costs, corporate planning, and the scope and economics of proposed expansions, infrastructure projects or other capital expenditures.
In addition, existing and potential new or amended legislation and regulation relating to the control and reduction of GHG emissions and mitigating climate change may materially restrict our operations, negatively impact demand for our services, the natural gas we distribute and/or the energy we transmit, limit development opportunities, force costly or otherwise burdensome changes to our operations or otherwise materially adversely affect us. For example, SB 100 (enacted in 2018) and SB 1020 (enacted in 2022) requires each California electric utility, including SDG&E, to
procure at least 50% of its annual electric energy requirements from renewable energy sources by 2026, 60% by 2030, 90% by 2035, and 95% by 2040. State law also 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, the Governor of California signed an executive order establishing a new statewide goal to achieve carbon neutrality as soon as possible, and no later than 2045, and achieve and maintain net negative emissions thereafter. The executive order calls on CARB to address this goal in future scoping plans, which affect several major sectors of California’s economy, including transportation, agriculture,
development, industrial and others. California has issued new climate initiatives in line with this statewide goal, including two executive orders requiring sales of all passenger vehicles to be zero-emission by 2035.
Moreover, the energy transition in California and elsewhere, including decarbonization goals, has introduced uncertainty in investor support over the long term, leading some to reduce investment in or divest from the energy sector. Maintaining investor confidence and attracting capital at a competitive cost will depend in part on successfully demonstrating our ability to reduce emissions associated with our operations and the energy we transmit, consistent with Sempra’s aim to have net-zero emissions by 2050 and SDG&E’s and SoCalGas’ aim to have net-zero emissions by 2045. Our ability to achieve this aim depends on many factors, some of which we do not control, including supportive energy laws and policies,
development, availability and adoption of alternative fuels, successful research and development efforts focused on low-carbon technologies that are economically and technically feasible, cooperation from our partners, financing sources and commercial counterparties, customer participation in conservation and energy efficiency programs, and our ability to execute our planned investments in and advancement of our
infrastructure. Although we have developed
interim targets and various plans designed to support California in reaching its GHG emissions and renewable energy mandates and our own energy goals, we may not be successful.
We will need to continue to expend capital and employee resources to develop and deploy new technologies and modernize grid systems in our efforts to support the clean energy transition in California and elsewhere and achieve our climate targets and those mandated by applicable authorities, which may not be recoverable in rates or, with respect to our non-regulated utility businesses, may not be able to be passed through to customers. Even if such costs are recoverable, the costs of these efforts and complying with these mandates, coupled with the necessary costs of investing for safety and reliability, may negatively impact the affordability of SDG&E’s and SoCalGas’ customer rates and, for our non-regulated utility businesses, may cause costs to
increase to levels that reduce customer demand and growth. SDG&E and SoCalGas, as well as any of our other businesses affected by GHG emissions mandates, may also be subject to fines and penalties if mandated renewable energy goals are not met, and all our businesses could suffer difficulties attracting investors and business partners, reputational harm and other negative effects if we do not meet or if we scale back our GHG emissions goals or there are negative views about our environmental disclosures or practices generally. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Our businesses are subject to numerous governmental regulations and complex tax and accounting requirements and may be materially adversely affected by them or any changes to them.
The electric power and natural gas
industries are subject to numerous governmental regulations, and our businesses are also subject to complex tax and accounting requirements. These regulations and requirements may undergo changes at the federal, state, local and foreign levels, including in response to economic or political conditions. Compliance with these regulations and requirements, including in the event of changes to them or how they are implemented, interpreted or enforced, could increase our operating costs and materially adversely affect how we conduct our business. New tax legislation, regulations or interpretations or changes in tax policies in the U.S. or other countries in which we operate or do business could negatively affect our tax expense and/or tax balances and our businesses generally. Any failure to comply with these regulations and requirements could subject us to fines and penalties, including criminal penalties in some cases, and result in the temporary or permanent shutdown of
certain facilities or operations. The occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Our operations are subject to rules relating to transactions among SDG&E, SoCalGas and other Sempra businesses. These rules are commonly referred to as “affiliate rules,” and they primarily impact transmission supply, capacity and marketing activities, including restricting our ability to sell natural gas or electricity to, or trade with, SDG&E and SoCalGas and their ability to complete these transactions with each other. These rules, as well as any changes to these rules or their interpretations or additional more restrictive CPUC or FERC rules related to transactions with affiliates, could materially adversely affect our operations and, in turn, our results of operations, financial condition, cash flows and/or prospects.
We
may be materially adversely affected by the outcome of litigation or other proceedings in which we are involved.
Our businesses are involved in a number of lawsuits, binding arbitrations, regulatory investigations and other proceedings. We discuss material pending proceedings in Note 16 of the Notes to Consolidated Financial Statements. We have spent, and continue to spend, substantial money, time and employee and management focus on these lawsuits and other proceedings. The uncertainties inherent in lawsuits and other proceedings make it difficult to estimate with any degree of certainty the timing, costs and ranges of costs or effects of resolving these matters. In addition, juries have demonstrated a willingness to grant large awards, including punitive damages, in response to personal injury, product liability, property damage and other claims. Accordingly, actual costs incurred have and may continue to differ materially
from insured or reserved amounts and may not be recoverable, in whole or in part, from insurance or in customer rates. Any of the foregoing could cause reputational damage and materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Wildfires in California pose risks to Sempra California (particularly SDG&E) and Sempra.
Potential for Increased and More Severe Wildfires
Over the past few years, California has been experiencing some of the largest wildfires (measured by acres burned) in its history. Frequent and severe drought conditions, inconsistent and extreme swings in precipitation, changes in vegetation, unseasonably warm temperatures, low humidity, strong winds and other factors have increased the duration of the wildfire season and the intensity, prevalence and difficulty of prevention and containment of wildfires in California, including in SDG&E’s and SoCalGas’ service territories. Changing weather patterns, including as a result of climate change, could cause these conditions to become even more extreme and unpredictable. These wildfires could
jeopardize SDG&E’s and SoCalGas’ electric and natural gas infrastructure and third-party property and result in temporary power shortages in SDG&E’s and SoCalGas’ service territories. Certain of California’s local land use policies and forestry management practices have been relaxed to allow for the construction and development of residential and commercial projects in high-risk fire areas, which could lead to increased third-party claims and greater losses in the event of fires in these areas for which SDG&E or SoCalGas may be liable. Any such wildfires in SDG&E’s and SoCalGas’ territories (or outside of these territories in the event the Wildfire Fund described below is materially diminished) could materially adversely affect SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects, which we discuss in this risk factor below and above under “Risks Related to All Sempra Businesses – Operational Risks.”
The Wildfire Legislation
In July 2019, the Wildfire Legislation was signed into law, which we discuss in Note 1 of the Notes to Consolidated Financial Statements. The Wildfire Legislation’s revised legal standard for the recovery of wildfire costs may not be implemented effectively or applied consistently, we may not be eligible for the Wildfire Legislation’s cap on wildfire-related liability if SDG&E fails to maintain a valid annual safety certification from the OEIS or meet other requirements of the legislation, and/or the Wildfire Fund could be exhausted due to claims against the fund by SDG&E or other participating IOUs as a result of fires in their respective service territories, any of which could have a material adverse effect on Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects. PG&E has indicated that it will seek
reimbursement from the Wildfire Fund for losses associated with the Dixie fire, which burned from July 2021 through October 2021 and was reported to be the largest single wildfire (measured by acres burned) in California history. In addition, the Wildfire Legislation did not change the doctrine of inverse condemnation, which imposes strict liability (meaning that liability is imposed regardless of fault) on a utility whose equipment, such as its electric distribution and transmission lines, is determined to be a cause of a fire. In such an event, the utility would be responsible for the costs of damages, including potential business interruption losses, and interest and attorneys’ fees, even if the utility has not been found negligent. The doctrine of inverse condemnation also is not exclusive of other theories of liability, including if the utility were found negligent, in which case additional liabilities, such as fire suppression, clean-up and evacuation costs, medical
expenses, and personal injury, punitive and other damages, could be imposed. We are unable to predict the impact of the Wildfire Legislation on SDG&E’s ability to recover costs and expenses in the event that SDG&E’s equipment is determined to be a cause of a fire, and specifically in the context of the application of inverse condemnation.
Cost Recovery Through Insurance or Rates
As a result of the strict liability standard applied to electric IOU-caused wildfires in California, substantial losses recently recorded by insurance companies, and the risk of an increase in the number and size of wildfires, obtaining insurance coverage for wildfires that could be caused by SDG&E (or, to a lesser extent, SoCalGas) has become increasingly difficult and costly. If these conditions continue or worsen, insurance for wildfire liabilities may become unavailable or may become prohibitively
expensive and we may be challenged or unsuccessful when we seek recovery of insurance cost increases through the regulatory process. In addition, insurance for wildfire liabilities may not be sufficient to cover all losses we may incur, or it may not be available in sufficient amounts to meet the $1.0 billion of primary insurance required by the Wildfire Legislation. We are unable to predict whether we would be able to recover in rates or from the Wildfire Fund the amount of any uninsured losses. A loss that is not fully insured, is not sufficiently covered by the Wildfire Fund and/or cannot be recovered in customer rates could materially adversely affect Sempra’s and one or both of SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
Although we expend significant resources on measures designed to mitigate wildfire risks, these measures may not be effective in preventing wildfires or reducing our wildfire-related losses and their costs may not be fully recoverable in rates. SDG&E is required by applicable California law to submit annual wildfire mitigation plans for approval by the OEIS and could be subject to increased risks if these plans are not approved in a timely manner or the measures set forth in the plans are not implemented effectively, as well as fines or penalties for any failure to comply with the approved plans. One of our wildfire mitigation and safety tools is to de-energize certain of our facilities when weather
conditions become extreme and there is elevated wildfire ignition risk. These “public safety power shutoffs” have been subject to scrutiny by various stakeholders, including customers, regulators and lawmakers, which could increase the risk of liability for damages associated with these events. Such costs may not be recoverable in rates. Unrecoverable costs, adverse legislation or rulemaking, scrutiny by key stakeholders, ineffective wildfire mitigation measures or other negative effects associated with these efforts could materially adversely affect Sempra’s and SDG&E’s results of operations, financial condition, cash flows and/or prospects.
The electricity industry is undergoing significant change, including increased deployment of DER, technological advancements, and political and regulatory developments.
Electric utilities
in California are experiencing increasing deployment of DER, such as solar generation, energy storage and energy efficiency and demand management technologies, and California’s environmental policy objectives are accelerating the pace and scope of these changes. This growth of DER and demand management will require further modernization of the electric distribution grid to, among other things, accommodate increasing two-way flows of electricity and increase the grid’s capacity to interconnect these resources. In addition, enabling California’s clean energy goals will require sustained investments in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, operational and data management systems, and electric vehicle infrastructure. The growth of third-party energy storage alternatives and other technologies also may increasingly compete with SDG&E’s traditional transmission and distribution infrastructure in delivering
electricity to consumers. The CPUC is conducting several proceedings regarding DER and demand management, including the evaluation of various projects and pilots; changes to the planning and operation of the electric distribution grid to prepare for higher penetration of DER; future grid modernization and grid investments; the deferral of traditional grid investments by DER; and the role of the electric distribution grid operator. These proceedings and the broader changes in California’s electricity industry could result in new regulations, policies and/or operational changes that could materially adversely affect SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.
SDG&E provides bundled electric procurement service through various resources that are typically procured on a long-term basis. Although SDG&E currently provides such procurement service for a portion of its customer
load, most customers receive procurement service from a load-serving entity other than SDG&E through programs such as CCA and DA, in which case SDG&E no longer procures energy for this departing load. CCA is only available if a customer’s local jurisdiction (city or county) offers such a program and DA is currently limited by a cap based on gigawatt hours. Several jurisdictions in SDG&E’s territory, including the City of San Diego, have implemented CCA, and additional jurisdictions are in the process of implementing or considering CCA. SDG&E’s historical energy procurement for future deliveries exceeds the needs of its remaining bundled customers as customers have elected CCA and DA services. To help achieve the goal of ratepayer indifference (as to whether or not customers’ energy is procured by SDG&E or by CCA or DA), the CPUC revised the Power Charge Indifference Adjustment framework. The purpose of the framework is to help ensure SDG&E’s procurement
cost obligations are more equitably shared among customers served by SDG&E and customers now served by CCA and DA. SDG&E implemented the framework on January 1, 2019. If the framework or other mechanisms designed to achieve ratepayer indifference do not perform as intended, if the law changes, or if the law is not interpreted or enforced as expected, SDG&E’s remaining bundled customers could experience large increases in rates for commodity costs under commitments made on behalf of CCA and DA customers prior to their departure or, if all such costs are not recoverable in rates, SDG&E could experience material increases in its unrecoverable commodity costs. Any of these outcomes could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Natural gas and natural gas storage have increasingly
been the subject of political and public scrutiny, including a desire by some to reduce or eliminate reliance on natural gas as an energy source.
Certain California legislators, as well as stakeholder, advocacy and activist groups, have expressed a desire to limit or eliminate reliance on natural gas as an energy source by advocating increased use of renewable electricity and electrification in lieu of the use of natural gas. Reducing methane emissions also has become a major focus of certain local and state agencies and the U.S. Administration, as well as the CPUC, resulting in passed or proposed legislation, regulation, policies and ordinances to prohibit or restrict the use and consumption of natural gas in new buildings, appliances and other applications. These actions could have the effect of reducing natural gas use over time.
CARB, California’s primary regulator for GHG emissions reduction programs, continues to pursue plans for reducing GHG emissions in line with California’s climate goals that include proposals to reduce natural gas demand through proposed building decarbonization measures (for example, zero-emission standards for space and water heaters), or through promoting legislation for increased renewable electricity generation. Additionally, the CEC’s Title 24 requirements mandate that new construction include electric-ready buildings and heat
pump technologies beginning in 2023.
The CPUC has an ongoing proceeding that seeks to establish a state-wide process to help utilities plan appropriate gas infrastructure portfolios as natural gas usage in the state is expected to decline. This includes a new gas infrastructure General Order (GO 177) requiring site-specific approvals for certain gas infrastructure projects as well as issuance of a CPUC staff proposal to develop a gas distribution infrastructure decommissioning framework. The CPUC may similarly enact measures to reduce natural gas demand (such as more aggressive energy efficiency programs), promote fuel substitution (such as replacement of natural gas appliances with electric appliances), and order changes (such as its recent decision to eliminate gas line extension allowances for new applications submitted on or after July 1, 2023).
A
substantial reduction in or the elimination of natural gas as an energy source in California without adequate and appropriate recovery of investments could result in impairment of some or all of SoCalGas’ and SDG&E’s natural gas infrastructure assets if they were not permitted to be repurposed for alternative fuels, were required to be depreciated on an accelerated basis or were to become stranded, which could have a material adverse effect on SoCalGas’, SDG&E’s and Sempra’s results of operations, financial conditions, cash flows and/or prospects.
SDG&E may incur significant costs and liabilities from its partial ownership of a nuclear facility being decommissioned.
SDG&E has a 20% ownership interest in SONGS, which we discuss in Note 15 of the Notes to Consolidated Financial Statements. SDG&E and each of the other
owners of SONGS is responsible for financing its share of the facility’s expenses and capital expenditures, including those related to decommissioning activities. Although the facility is being decommissioned, SDG&E’s ownership interest in SONGS continues to subject it to risks, including:
▪the potential release of radioactive material
▪the potential harmful effects from the former operation of the facility
▪limitations on the insurance commercially available to cover losses associated with operating and decommissioning the facility
▪uncertainties with respect to the technological and financial aspects of decommissioning the facility
SDG&E
maintains the SONGS NDT to provide funds for nuclear decommissioning. Trust assets have been generally invested in equity and debt securities, which are subject to market fluctuations. A decline in the market value of trust assets, an adverse change in the law regarding funding requirements for decommissioning trusts, or changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment due to inflationary pressures or otherwise could increase the funding requirements for these trusts, which costs may not be fully recoverable in rates. In addition, CPUC approval is required to make withdrawals from the NDT, and CPUC approval for certain expenditures may be denied if the CPUC determines the expenditures are unreasonable. In addition, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the NDT. Rate recovery for overruns would
require CPUC approval, which may not occur.
The occurrence of any of these events could result in a reduction in our expected recovery and have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Legal and Regulatory Risks
SDG&E and SoCalGas are subject to extensive regulation by federal, state and local legislative and regulatory authorities, which may materially adversely affect Sempra, SDG&E and SoCalGas.
Rates and Other Financial Matters
The CPUC regulates SDG&E’s and SoCalGas’ customer rates, except for SDG&E’s electric transmission rates that are regulated by the FERC, and conditions of service. The CPUC also regulates SDG&E’s and SoCalGas’ sales of
securities, rates of return, capital structure, rates of depreciation, long-term resource procurement and other financial matters in various ratemaking proceedings. The CPUC periodically approves SDG&E’s and SoCalGas’ customer rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investments while incorporating a risk-based decision-making framework, as well as settlements with third parties. The outcome of ratemaking proceedings can be affected by various
factors,
many of which are not in our control, including the level of opposition by intervening parties; any rejection by the CPUC of settlements with third parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of regulators, consumer and other stakeholder groups and customers. These ratemaking proceedings include decisions about major programs in which SDG&E and SoCalGas make investments under an approved CPUC framework, such as wildfire mitigation and pipeline and storage integrity and safety enhancement programs, but which investments may remain subject to a CPUC filing or reasonableness review with potentially unclear standards or other factors as described above that may result in the disallowance of incurred costs. SDG&E and SoCalGas also may be required to incur costs and make investments to comply with proposed legislative and regulatory requirements and initiatives,
including those related to California’s climate goals and policies, and their ability to recover these costs and investments may depend on the final form of the legislative or regulatory requirements and the ratemaking mechanisms associated with them. Recovery can also be affected by the timing and process of the ratemaking mechanism, in which there can be a significant time lag between when costs are incurred and when those costs are recovered in customers’ rates and material differences between the forecasted and authorized costs embedded in rates (which are set on a prospective basis) and the actual costs incurred. The CPUC may also experience delays in its decisions on recovery or may deny recovery altogether on the basis that costs were not reasonably or prudently incurred or for other reasons. Even if recoverable, the cost of investments to support the clean energy transition in California while also investing in necessary safety and reliability may negatively
impact the affordability of SDG&E’s and SoCalGas’ customer rates and their and Sempra’s results of operations, financial condition, cash flows and/or prospects.
In addition, a CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and authorized return on rate base, and the CCM applies in the interim years and considers changes in the cost of capital based on changes in interest rates for each 12-month period ending September 30 (the measurement period). Alternatively, each of SDG&E and SoCalGas are permitted to file a cost of capital application in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole to have its cost of capital determined in lieu of the CCM. Any such rate change due to a downward trigger of the CCM could have a material adverse effect on Sempra’s
and the applicable utility’s results of operations, financial condition, cash flows and/or prospects. We discuss the CCM in “Part I – Item 1. Business - Ratemaking Mechanisms – Sempra California – Cost of Capital Proceedings,” and in Note 4 of the Notes to Consolidated Financial Statements.
The FERC regulates electric transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the rates of return on investments in electric transmission assets, and other similar matters involving SDG&E. These ratemaking mechanisms are subject to many risks similar to those described above regarding the CPUC ratemaking proceedings.
CPUC Authority Over Operational Matters
The CPUC has regulatory authority related to safety standards and practices, competitive conditions, reliability and planning,
affiliate relationships and a wide range of other operational matters, including citation programs concerning matters such as safety activity, disconnection and billing practices, resource adequacy and environmental compliance. Many of these standards and citation programs are becoming more stringent and could impose significant penalties, including enforcement programs under which the CPUC staff can issue citations that in some cases can impose substantial fines. The CPUC also continues to explore expansion of its programs to provide additional oversight. The CPUC conducts reviews and audits of the matters under its authority and could launch investigations or open proceedings at any time on any such matter it deems appropriate, the results of which could lead to citations, disallowances, fines and penalties, as well as corrective or mitigation actions required to address any noncompliance that may not be sufficiently funded by customer rates or at all. Any such occurrence
could have a material adverse effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
We discuss various CPUC proceedings relating to SDG&E and SoCalGas in Notes 4 and 16 of the Notes to Consolidated Financial Statements.
Potential Regulatory Changes and Influence of Other Organizations
SDG&E, SoCalGas and Sempra may be materially adversely affected by revisions or reinterpretations of existing or new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies, any of which could change how SDG&E and SoCalGas operate, affect their ability to recover various costs through rates or adjustment mechanisms, require them to incur additional expenses or otherwise materially adversely affect their and Sempra’s results
of operations, financial condition, cash flows and/or prospects.
SDG&E and SoCalGas are also affected by numerous advocacy groups, including California Public Advocates Office, The Utility Reform Network, Utility Consumers’ Action Network and the Sierra Club. Any success by any of these groups in directly or
indirectly influencing regulatory bodies with authority over their operations could have a material
adverse effect on SDG&E’s, SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
SoCalGas has incurred and may continue to incur significant costs, expenses and other liabilities related to the Leak.
From October 23, 2015 through February 11, 2016, SoCalGas experienced the Leak, which we describe in Note 16 of the Notes to Consolidated Financial Statements.
Litigation
In September 2021, SoCalGas and Sempra entered into an agreement with counsel to resolve lawsuits filed by approximately 36,000 plaintiffs (the Individual Plaintiffs) against SoCalGas and Sempra related to the Leak resulting in a payment of approximately $1.8 billion. The Individual Plaintiffs
who do not participate in that settlement (the Remaining Individual Plaintiffs) will be able to continue to pursue their claims. As of February 21, 2023, lawsuits filed by the Remaining Individual Plaintiffs and several shareholder derivative actions are pending against SoCalGas related to the Leak, some of which have also named Sempra and/or certain officers and directors of SoCalGas and Sempra. Additional litigation may be filed against us related to the Leak or our responses to it. The costs of defending against, settling or otherwise resolving the pending lawsuits or any new litigation could materially adversely affect SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects. We discuss these risks above under “Risks Related to All Sempra Businesses – Legal and Regulatory Risks” and in this risk factor below under “Estimated Costs, Insurance and Accounting and Other
Impacts.”
Regulatory Proceedings
SoCalGas has been subject to an OII to investigate and consider, among other things, what damages, fines or other penalties, if any, should be imposed against SoCalGas in connection with the Leak (the Leak OII). In October 2022, SoCalGas executed a settlement agreement with SED and the Public Advocates Office at the CPUC to resolve all aspects of the Leak OII, which is subject to CPUC approval. The settlement agreement provides for financial penalties, certain costs that SoCalGas will reimburse, a violation of California Public Utilities Code section 451, and costs previously incurred by SoCalGas for which it will not seek recovery from ratepayers, among other provisions. Other investigations related to the Leak could result in additional findings of violations of laws, orders, rules or regulations as well as fines and penalties, any of which
could involve substantial costs and cause reputational damage. In addition, SoCalGas may incur higher operating costs and additional capital expenditures as a result of new investigations or new laws, orders, rules and regulations arising out of this incident, or our responses thereto, which may not be recoverable through insurance or in customer rates. The occurrence of any of these risks could materially adversely affect SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Natural Gas Storage Operations and Reliability
In February 2017, the CPUC opened a proceeding pursuant to SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including analyzing alternative means for meeting or avoiding the
demand for the facility’s services if it were eliminated.
If the Aliso Canyon natural gas storage facility were to be permanently closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we may record an impairment of the facility, which could be material, incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized. Any such outcome could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Cost Estimate, Insurance and Accounting and Other Impacts
At December 31, 2022, SoCalGas
estimates certain costs related to the Leak are $3,486 million (the cost estimate), including $1,279 million of costs recovered from insurance. Other than insurance for directors’ and officers’ liability, we have exhausted all of our insurance for 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. At December 31, 2022, $129 million of the cost estimate is accrued in Reserve for Aliso Canyon Costs and $4 million of the cost estimate is accrued in Deferred Credits and Other on SoCalGas’ and Sempra’s Consolidated Balance Sheets.
The civil litigation that remains pending against us related to the Leak seeks compensatory, statutory and punitive damages, restitution, and civil and administrative fines, penalties and other costs. We also
could be subject to damages, fines or other penalties as a result of the pending regulatory investigation related to the Leak. Except for the amounts paid or estimated to settle
certain pending legal and regulatory matters as we describe in Note 16 of the Notes to Consolidated Financial Statements, the cost estimate does not include any amounts necessary to resolve pending litigation or regulatory proceedings, other potential litigation or other costs,
in each case to the extent it is not possible to predict at this time the outcome of these actions or reasonably estimate the possible costs or a range of possible costs. Further, we are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued. The costs or losses not included in the cost estimate could be significant and could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Any failure by the CPUC to adequately reform SDG&E’s rate structure could have a material adverse effect on SDG&E and Sempra.
The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation (primarily solar installations) for residential and business customers. Depending on when the on-site generation was
installed, NEM customers receive a full retail rate or a reduced retail rate for energy they generate but do not use that is fed to the utility’s power grid, which results in these customers not paying their proportionate share of the cost of maintaining and operating the electric transmission and distribution system, subject to certain exceptions, but still receiving electricity from the system when their self-generation is inadequate to meet their electricity needs. As more and higher electric-use customers switch to NEM and self-generate energy, the burden on remaining non-NEM customers, who effectively subsidize the unpaid NEM costs, increases, which in turn encourages more self-generation and further increases rate pressure on remaining non-NEM customers.
The current electric residential rate structure in California is primarily based on consumption volume, which places a higher rate burden on customers with higher electric
use while subsidizing lower-use customers. In August 2020, the CPUC initiated a rulemaking to further develop a successor to the existing NEM tariff. In November 2022, a previous proposed decision was withdrawn and a new proposed decision was issued, recommending substantial reform of the NEM program through the establishment of a new Net Billing Tariff that would apply to new net metered customers. The new Net Billing Tariff revises the current NEM structure for new customers with a retail export compensation rate that is better aligned with the value provided to the grid by behind-the-meter energy generation systems and retail import rates that encourage electrification and adoption of solar systems paired with storage. The new Net Billing Tariff is designed to compensate customers for the value of their exports to the grid based on avoided cost. In December 2022, the CPUC approved the new Net Billing Tariff for customers who interconnect their qualifying on-site renewable
generation after April 14, 2023. Additionally, in response to California legislation adopted in 2022, the CPUC has initiated a rulemaking to broadly restructure the way fixed costs are collected, moving from volumetric charges to an income-graduated fixed charge for default residential rates by July 1, 2024. The intent of such a fixed charge would be to further help reduce cost shifts through an equitable approach to the distribution of electric costs. Depending on the effectiveness of the new Net Billing Tariff and any new rules related to fixed charges, which are uncertain, the risks associated with the existing NEM tariff could continue or increase.
SDG&E believes the establishment of a charge independent of consumption volume for residential customers is critical to help distribute rates among all customers that rely
on the electric transmission and distribution system, including those participating in the NEM program. The absence of a charge independent of consumption volume coupled with the continuing increase of solar installation and other forms of self-generation, as well as the progression of DER and energy efficiency initiatives that could also reduce delivered volumes, could adversely impact electricity rates and the reliability of the electric transmission and distribution system. Any such impact could subject SDG&E to increased customer dissatisfaction, increased likelihood of noncompliance with CPUC or other safety or operational standards and increased risks attendant to any such noncompliance, as we discuss above, as well as increased costs, including power procurement, operating and capital costs, and potential disallowance of recovery for these costs.
If the CPUC does not continue to adequately reform SDG&E’s residential
rate structure for all customers to better achieve reasonable, cost-based electric rates that are competitive with alternative sources of power and adequate to maintain the reliability of the electric transmission and distribution system, such failure could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Certain ring-fencing measures, governance mechanisms and commitments limit our ability to influence the management, operations and policies of Oncor.
Various “ring-fencing” measures, governance mechanisms and commitments are in place that create legal and financial separation between Oncor Holdings, Oncor and their subsidiaries, on the one hand, and Sempra and its affiliates and subsidiaries, on the other hand. These measures are designed to enhance Oncor’s separateness from its owners and mitigate the risk that Oncor would be negatively impacted by a bankruptcy or other adverse financial development affecting its owners. These measures subject us and Oncor to various restrictions, including:
▪seven
members of Oncor’s 13-person board of directors must be independent directors in all material respects under the rules of the NYSE in relation to Sempra and its affiliates and any other owners of Oncor, and also must have no material relationship with Sempra or its affiliates or any other owners of Oncor currently or within the previous 10 years; of the six remaining directors, two must be designated by Sempra, two must be designated by Oncor’s minority owner, TTI, and two must be current or former Oncor officers
▪Oncor will not pay dividends or other distributions (except for contractual tax payments) if (i) a majority of Oncor’s independent directors or any of the directors appointed by TTI determines that it is in the best interest of Oncor to retain such amounts to meet expected future requirements, (ii) the payment would cause Oncor’s debt-to-equity ratio to exceed the debt-to-equity ratio
approved by the PUCT, or (iii) unless otherwise allowed by the PUCT, Oncor’s senior secured debt credit rating by any of the Rating Agencies falls below BBB (or Baa2 for Moody’s)
▪there must be certain “separateness measures” maintained to reinforce the legal and financial separation of Oncor from Sempra, including a requirement that dealings between Oncor and Sempra or Sempra’s affiliates (other than Oncor Holdings and its subsidiaries) must be on an arm’s-length basis, limitations on affiliate transactions and a prohibition on pledging Oncor assets or membership interests for any entity other than Oncor
▪a majority of Oncor’s independent directors and the directors designated by TTI that are present and voting (with at least one required to be present and voting) must approve any annual or multi-year budget if
the aggregate amount of capital expenditures or O&M in the budget differs by more than 10% from the corresponding amounts in the budget for the preceding fiscal year or multi-year period, as applicable
As a result of these measures, we do not control Oncor Holdings or Oncor, and we have limited ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important matters. We have limited representation on the Oncor Holdings and Oncor boards of directors, which are each controlled by independent directors. Moreover, all directors of Oncor, including the directors we have appointed, have considerable autonomy and have a duty to act in the best interest of Oncor consistent with the approved ring-fence and Delaware law, which may in some cases be contrary to our interests. To the extent
the directors approve or Oncor otherwise pursues actions that are not in our interest, our results of operations, financial condition, cash flows and/or prospects may be materially adversely affected.
Industry-Related Risks
Changes in the regulation or operation of the electric utility industry and/or the ERCOT market, as well as the outcome of regulatory proceedings, could materially adversely affect Oncor, which could materially adversely affect us.
Oncor operates in the electric utility industry and, as a result, it is subject to many of the same or similar risks as Sempra California as we describe above under “Risks Related to Sempra California,” particularly with respect to regulation by federal, state, and local legislative and regulatory authorities regarding rates and other financial matters as well as operational matters.
Oncor operates in the ERCOT market. In ERCOT, rates are set by the PUCT based on a historical test year, and as a result, the rates Oncor is allowed to charge generally will not exactly match its costs at any given point in time and there is no assurance that it will be able to earn its full return on invested capital. Further, the PUCT may not approve all items requested by Oncor in any rate proceeding, such as Oncor’s base rate review currently pending with the PUCT, including, among other things, recovery of all costs in rates, capital structure and authorized ROE. Failure to receive approval of its requests in any rate proceeding could adversely impact Oncor, which could adversely impact us, and those impacts could potentially be material.
The costs and burdens associated with complying with the various legislative and regulatory requirements to which Oncor is subject at the federal, state, and local levels and adjusting
Oncor’s business and operations in response to legislative and
regulatory developments, including changes in ERCOT, and any fines or penalties that could result from any noncompliance, may have a material adverse effect on Oncor. In addition, any economic weakness in the ERCOT market or slowing growth in Oncor’s service territory could lead to reduced electricity demand, which could materially adversely affect Oncor. Moreover, legislative, regulatory,
market or industry activities could adversely impact Oncor’s collections and cash flows and jeopardize the predictability of utility earnings. For instance, the PUCT has instituted various projects reviewing the regulatory framework regarding DER and other non-traditional technologies. As DER usage continues to grow, regulatory decisions made with respect to DER, including with respect to ERCOT market rules and transmission and distribution utilities’ ability to invest in non-traditional electricity delivery solutions, could adversely impact Oncor’s revenues and operations. If Oncor does not successfully respond to any legislative, regulatory, 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.
Financial
Risks
Oncor could have liquidity needs that necessitate additional investments.
Oncor’s business is capital-intensive, with significant capital spending expected in future periods, and it relies on external financing as a significant source of liquidity for its capital requirements. In the past, Oncor has financed much of its cash needs from operations and with proceeds from indebtedness, but these sources of capital may not be adequate or available on reasonable terms or at reasonable prices in the future. Because our commitments to the PUCT prohibit us from making loans to Oncor, we may elect to make capital contributions to Oncor if it fails to meet its capital requirements or is unable to access sufficient capital from other sources to finance its ongoing needs. Any such investments could be substantial, would reduce the cash available to us for other purposes, and could increase
our indebtedness, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Sempra could incur substantial tax liabilities if EFH’s 2016 spin-off of Vistra is deemed to be taxable.
As part of its ongoing bankruptcy proceedings, in 2016, EFH distributed all the outstanding shares of common stock of its subsidiary Vistra Energy Corp. (formerly TCEH Corp. and referred to herein as Vistra) to certain creditors of TCEH LLC (the spin-off), and Vistra became an independent, publicly traded company. Vistra’s spin-off from EFH was intended to qualify for partially tax-free treatment to EFH and its shareholders under Sections 368(a)(1)(G), 355 and 356 of the U.S. Internal Revenue Code of 1986 (as amended) (collectively referred to as the Intended Tax Treatment). In connection with and as a condition to the spin-off, EFH received
a private letter ruling from the IRS regarding certain issues relating to the Intended Tax Treatment, as well as tax opinions from counsel to EFH and Vistra regarding certain aspects of the spin-off not covered by the private letter ruling.
In connection with the signing and closing of the merger of EFH (now Sempra Texas Holdings Corp. and a subsidiary of Sempra) with an indirect subsidiary of Sempra (the Merger), EFH sought and received a supplemental private letter ruling from the IRS and Sempra and EFH received tax opinions from their respective counsels that generally provide that the Merger will not affect the conclusions reached in, respectively, the IRS private letter ruling and tax opinions issued with respect to the spin-off described above. Similar to the IRS private letter ruling and opinions issued with respect to the spin-off, the supplemental private letter ruling is generally binding on the IRS and any opinions
issued with respect to the Merger are based on factual representations and assumptions, as well as certain undertakings, made by Sempra and EFH. If such representations and assumptions are untrue or incomplete, any such undertakings are not complied with, or the facts upon which the IRS supplemental private letter ruling or tax opinions (which will not impact the IRS position on the transactions) are based are different from the actual facts relating to the Merger, the tax opinions and/or supplemental private letter ruling may not be valid and could be challenged by the IRS. Even though Sempra Texas Holdings Corp. would have administrative appeal rights if the IRS were to invalidate its private letter ruling and/or supplemental private letter ruling, including the right to challenge any adverse IRS position in court, any such appeal would be subject to uncertainties and could fail. If it is ultimately determined that the Merger caused the spin-off not to qualify for
the Intended Tax Treatment, Sempra, through its ownership of Sempra Texas Holdings Corp., could incur substantial tax liabilities, which would materially reduce the value associated with our indirect investment in Oncor and could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Project development activities may not be successful, projects under construction may not be completed on schedule or within budget, and completed projects may not operate at expected levels, any of which could materially adversely affect us.
All Energy Infrastructure Projects
We are involved in a number of energy infrastructure projects in various stages of development and construction, which subject us to numerous risks. Success in developing each project is contingent upon, among other things:
▪our financial condition and cash flows and other factors that impact our ability to invest sufficient funds in the project, including for preliminary activities that may need
to be accomplished before we can determine whether the project is feasible or economically attractive
▪project assessment and design and our ability to foresee and incorporate new and developing trends and technologies in the energy industry, such as our pursuit of projects and design solutions to help enable our and our customers’ climate goals
▪our ability to reach a final investment decision or meet other milestones, which may be influenced by external factors outside our control, including the global economy and energy and financial markets, actions by regulators, achieving necessary internal and external approvals from project partners (if applicable) and others, and many of the other factors described in this risk factor
▪negotiation of satisfactory
EPC agreements, including any renegotiation that may be required in the event of delays in final investment decisions or failures to meet other specified deadlines
▪progressing relationships from MOUs, HOAs or similar arrangements, which are non-binding and generally do not impose obligations on any of the parties, to execution of definitive agreements and participation in the project
▪identification of suitable partners, customers, suppliers and other necessary counterparties, negotiation of satisfactory equity, purchase, sale, supply, transportation and other appropriate commercial agreements, and satisfaction of any conditions to effectiveness of such agreements, including reaching a positive final investment decision within agreed timelines
▪timely
receipt and maintenance of required governmental permits, licenses and other authorizations that do not impose material conditions and are otherwise granted under terms we find reasonable
▪our project partners’, contractors’ and other counterparties’ willingness and financial or other ability to make their required investments or fulfill their contractual commitments on a timely basis
▪timely, satisfactory and on-budget completion of construction, which could be negatively affected by engineering problems, work stoppages, unavailability or increased costs of materials, equipment, labor and commodities due to inflation or supply chain or other issues, contractor nonperformance and a variety of other factors, many of which we discuss above under “Risks Related to All Sempra Businesses – Operational Risks” and elsewhere
in this risk factor
▪implementation of new or changes to existing laws or regulations that impact our infrastructure or the energy sector generally
▪obtaining adequate and reasonably priced financing for the project, particularly in light of rising inflation and interest rates
▪the absence of hidden defects or inherited environmental liabilities for the site of the project
▪fast and cost-effective resolution of any litigation or unsettled property rights affecting the project
▪geopolitical events and other uncertainties, such as the war in Ukraine
Any failures
with respect to the above factors or other factors material to any particular project could involve additional costs, otherwise negatively affect our ability to successfully complete the project and force us to impair or write off amounts we have invested in the project. If we are unable to complete a development project, if we experience delays, or if construction, financing or other project costs exceed our estimated budgets and we are required to make additional capital contributions, we may never recover or receive an adequate or any return on our investment and other resources expended on the project and our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected.
The operation of existing facilities and any future projects we are able to complete involves many risks, including the potential for unforeseen design flaws, engineering challenges, equipment failures or
the breakdown for other reasons of facilities, equipment or processes; labor disputes; fuel interruption; environmental contamination; and the other operational risks that we discuss above under “Risks Related to All Sempra Businesses – Operational Risks.” Any of these events could lead to our facilities being idle for an extended period of time or operating below expected levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
In addition to the risks described above that are applicable to all our energy infrastructure projects, we are exposed to additional risks in connection with our LNG export projects, including the ECA LNG Phase 1 project under construction and our potential development of additional LNG export facilities. We discuss our LNG export projects in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sempra Infrastructure.” Each of these projects faces numerous risks. Our ability to reach a final investment decision for each project and, if a positive decision is made and a project is completed, the overall success of the project are dependent on global energy markets, including natural gas and oil supply, demand and pricing, the ability to reach advantageous agreements with our counterparties, including our partners, off-takers, and EPC contractors, risks inherent in construction, and the ability
to obtain and maintain government approvals, among other things. In general, depressed natural gas and LNG prices in the markets we intend to serve due to shifts in supply or other factors could reduce the pricing and cost advantages of exporting domestically produced natural gas and LNG, which could lead to decreased demand. In addition, global oil prices and their associated current and forward projections could reduce demand for natural gas and LNG in some sectors. Although demand for natural gas is currently strong due to the geopolitical consequences of the war in Ukraine and increased recognition of the importance of energy security, a reduction in natural gas demand could also occur from higher penetration of alternative fuels in new power generation, or as a result of calls by some to limit or eliminate reliance on natural gas as an energy source globally. Oil prices could also make LNG projects in other parts of the world more feasible and competitive with LNG
projects in North America, thus increasing supply and competition for any available LNG demand. Moreover, because LNG projects take a number of years to develop and construct, it is difficult to match current and expected demand with the projected supply from projects under development. Any of these occurrences could impact competition and prospects for developing LNG export projects and negatively affect the performance and prospects of any of our projects that are or become operational.
Our projects may face distinct disadvantages relative to some LNG projects being pursued by other project developers, including:
▪The proposed Cameron LNG Phase 2 project is subject to certain restrictions and conditions under the financing agreements for the Cameron LNG Phase 1 facility and requires unanimous consent of all JV members, including with respect to the
equity investment obligations of each partner. We may not be able to satisfy these conditions and requirements, in which case our ability to develop the Cameron LNG Phase 2 project would be jeopardized.
▪The ECA LNG projects under construction and in development are subject to ongoing land and permit disputes that could obstruct efforts to find or maintain suitable partners, customers and financing arrangements and hinder or halt construction and, if the projects are completed, operations. We discuss these risks below and under “Risks Related to Sempra Infrastructure – Legal Risks.” In addition, the Mexican regulatory process and overlay of U.S. regulation for natural gas exports to LNG facilities in Mexico are not well developed, which, among other factors, contributed to delays obtaining a necessary permit from the Mexican government for the ECA LNG Phase 1 project and could cause similar
delays or other hurdles in the future and lead to difficulties finding or maintaining suitable partners, customers and financing arrangements. We have entered into contracts with affiliates and third parties, subject to certain conditions, to supply and transport gas across the U.S.-Mexico border to meet the requirements of the ECA LNG Phase 1 project if and when it becomes operational. If affiliates or third parties experience delays or fail to obtain and maintain necessary permits and arrangements to provide such supply or transportation services or if we fail to maintain adequate gas supply and transportation agreements to support the project fully, it could cause additional costs or delays to the ECA LNG Phase 1 project. Finally, although we have planned measures to not disrupt operations at the ECA Regas Facility with the construction or operation of the ECA LNG Phase 1 project, these measures may not be effective. Moreover, we expect construction of the proposed
ECA LNG Phase 2 project to conflict with ECA Regas Facility operations, making the decisions on whether, when and how to pursue the ECA LNG Phase 2 project dependent in part on whether the investment in this project would, over the long term, be more beneficial than continuing to provide regasification services under existing contracts for 100% of the ECA Regas Facility’s capacity through 2028.
▪The PA LNG projects in development are to be located at a greenfield site and therefore are subject to disadvantages relative to projects being developed at brownfield sites, including increased time and costs to develop and construct the project.
Development of these or any other LNG export projects will depend on the ability of our existing pipeline interconnections to be expanded or the ability to permit and construct new pipeline facilities, each of which
may require us to enter into additional pipeline interconnection agreements with third-party pipelines. We and third parties may not be able to successfully develop and construct such new pipeline facilities, or we may not be able to secure such additional pipeline interconnections on commercially reasonable terms or at all.
The capital requirements for LNG export projects that we decide to pursue can be significant, even if we ultimately decide not to make a positive final investment decision. In addition, our proposed facilities may not be completed in accordance with estimated timelines or budgets or at all as a result of the above or other factors, and delays, cost overruns or our inability to complete one or more of these projects could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We may become involved in various financing arrangements with respect to any of our energy infrastructure projects, such as guarantees, indemnities or loans. These arrangements could expose us to additional risks, including exposure to losses upon the occurrence of certain events related to the development, construction, operation or financing of the applicable projects that could have a material adverse effect on our future results of operations, financial condition,
cash flows and/or prospects.
We are dependent on the equipment provided by third parties to operate the Cameron LNG Phase 1 facility and the failure of such equipment may adversely impact our business and performance.
Cameron LNG JV has experienced operating issues with equipment provided by third-party vendors, which have caused reductions in operating capacity and the declaration of force majeure events by Cameron LNG JV under its tolling agreements for its Cameron LNG Phase 1 facility. Certain of Cameron LNG JV’s customers have raised objections regarding these force majeure declarations, and Cameron LNG JV’s customers may raise objections in the future regarding these declarations or other force majeure declarations for similar operating issues. Cameron LNG JV’s customers have obtained certain, and may in the future obtain additional, quantities of excess LNG production in connection
with these and certain other force majeure events, and future force majeure events may also lead to the additional accrual of similar rights. The requirement to deliver excess LNG production to these customers in connection with these force majeure events has had, and in the future could have, an adverse impact on Sempra Infrastructure’s and our business and cash flows because Cameron LNG JV loses fees related to the excess production.
These and other operational issues arising from equipment or facilities provided by third-party vendors may require us to undertake remediation, repair or equipment replacement activities that could result in reductions or cessations in production from our facilities. Although we are seeking to enforce warranty and other claims against our EPC contractors and other equipment vendors and suppliers, we may face challenges in successfully enforcing these claims against these third parties. Any such
occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Fixed-price long-term contracts for services or commodities expose our businesses to inflationary pressures.
Sempra Infrastructure seeks to secure long-term contracts for services and commodities in an effort to optimize the use of its facilities, reduce volatility in earnings and support the construction of new infrastructure. If these contracts are at fixed prices, their profitability may be negatively affected by inflationary pressures, including increased labor, materials, equipment, commodities and other operational costs, rising interest rates that affect financing costs and changes in applicable exchange rates. We may try to mitigate these risks by, among other things, using variable pricing tied to market indices, anticipating and providing for cost
escalation when bidding on projects, contracting for direct pass-through of operating costs and/or entering into hedges. However, these measures may not fully or substantially offset any increases in operating expenses or financing costs caused by inflationary pressures and their use could introduce additional risks, any of which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Increased competition could materially adversely affect us.
The markets in which we operate are characterized by numerous strong and capable competitors, many of which have extensive and diversified development and/or operating experience domestically and internationally and financial resources similar to or greater than ours. In particular, the natural gas pipeline, storage and LNG market segments recently have been characterized by strong
and increasing competition for winning new development projects and acquiring existing assets. In addition, our Mexican natural gas distribution business faces increased competition now that its former exclusivity period with respect to its distribution zones has expired and other distributors are legally permitted to build and operate natural gas distribution systems and compete to attract customers in the locations where it operates. These competitive factors could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
We may not be able to enter into, maintain, extend or replace long-term supply, sales or capacity agreements.
The ECA Regas Facility has long-term capacity agreements with a limited number of counterparties, and also may enter into short-term and/or long-term supply agreements to purchase LNG to be received,
stored and regasified for sale to other parties. In addition, Cameron LNG JV has long-term liquefaction and regasification tolling agreements with three counterparties that collectively subscribe for the full nameplate capacity of the Cameron LNG Phase 1 facility. The long-term nature of these agreements and the small number of customers at each of these facilities exposes us to risks, including increased risk if these counterparties fail to meet their contractual obligations on a timely basis, increased credit risks, and risks associated with the long-term nature of our relationships with these counterparties, including increased impacts of disputes or other similar issues which we have experienced in the past. Any such issues that arise in the future with respect to our long-term contracts, including any that may be caused by or related to the war in Ukraine, could lead to significant legal and other costs, result in cancelation of certain key contracts or otherwise
adversely affect our relationships with long-term customers, suppliers or partners, and could negatively
impact the reliability of revenues from the applicable projects and the prospects for any implicated development projects. Any such event could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Sempra Infrastructure’s ability to enter into new
or replace existing long-term capacity agreements for its natural gas pipeline operations is dependent on, among other factors, demand for and supply of LNG and/or natural gas from its transportation customers, which may include our LNG export facilities. A decrease in demand for or supply of LNG or natural gas from such customers or the occurrence of other events that hinder Sempra Infrastructure from maintaining such agreements or establishing new ones could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
The electric generation and wholesale power sales industries are highly competitive. As more plants are built, supplies of energy and related products may exceed demand, competitive pressures may increase and wholesale electricity prices may decline or become more volatile. Without long-term power sales agreements, our revenues may be subject to increased volatility,
and we may be unable to sell the power that Sempra Infrastructure’s facilities are capable of producing or sell it at favorable prices, any of which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
We rely on transportation assets and services, much of which we do not own or control, to deliver natural gas and electricity.
We depend on electric transmission lines, natural gas pipelines and other transportation facilities and services owned and operated by third parties to, among other things:
▪deliver the natural gas, LNG, electricity and LPG we sell to customers or use for our LNG export facilities
▪supply natural gas to our gas storage and electric generation facilities
▪provide
retail energy services to customers
If transportation is disrupted, if the construction of new or modified interconnecting infrastructure is not completed on schedule or if capacity is inadequate, we may not be able to move forward with our projects on schedule, we may be unable to sell and deliver our commodities, electricity and other services to our customers, we may be responsible for damages incurred by these customers, such as the cost of acquiring alternative supplies at then-current spot market rates, and we could lose customers that may be difficult to replace in competitive market conditions. Any such occurrence could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Financial Risks
Our international businesses and operations expose us to foreign currency and inflation
risks.
Our operations in Mexico pose foreign currency and inflation risks. Exchange and inflation rates with respect to the Mexican peso and fluctuations in those rates may have an impact on the revenue, costs and cash flows from our international operations, which could materially adversely affect our results of operations, financial condition, cash flows and/or prospects. We may attempt to hedge cross-currency transactions and earnings exposure through various means, including financial instruments and short-term investments, but these hedges may not fully achieve our objectives of mitigating earnings volatility that would otherwise occur due to exchange rate fluctuations. Because we do not hedge our net investments in foreign countries, we are susceptible to volatility in OCI caused by exchange rate fluctuations for entities whose functional currencies are not the U.S. dollar. Moreover, Mexico has experienced periods of
high inflation and exchange rate instability in the past, and severe devaluation of the Mexican peso could result in governmental intervention to institute restrictive exchange control policies, as has occurred before in Mexico and other Latin American countries. We discuss our foreign currency exposure at our Mexican subsidiaries in “Part II – Item 7. MD&A” and “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Our businesses are exposed to market risks, including fluctuations in commodity prices, that could materially adversely affect us.
We buy energy-related commodities from time to time for pipeline operations, LNG facilities or power plants to satisfy contractual obligations with customers. The regional and other markets in which we purchase these commodities are competitive and can be subject to significant pricing volatility
as a result of many factors, including adverse weather conditions, supply and demand changes, availability of competitively priced alternative energy sources, commodity production levels and storage capacity, energy and environmental legislation and regulations, and economic and financial market conditions. Our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities we buy change in a direction or manner not anticipated and for which we have not provided adequately through purchase or sale commitments or other hedging transactions.
Our international businesses and operations expose us to increased legal, regulatory, tax, economic, geopolitical and management oversight risks and challenges.
Overview
We own or have interests in a variety of energy infrastructure assets in Mexico, and we do business with companies based in foreign markets, including particularly our LNG export operations. Conducting these activities in foreign jurisdictions subjects us to complex management, security, political, legal, economic and financial risks that vary by country, many of which may differ from and potentially be greater than those associated with our wholly
domestic businesses, and the occurrence of any of these risks could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. These risks include the following and the other risks discussed in this risk factor below:
▪compliance with tax, trade, environmental and other foreign laws and regulations, including legal limitations on ownership in some foreign countries and inadequate or inconsistent enforcement of regulations
▪actions by local regulatory bodies, including setting rates and tariffs that may be earned by or charged to our businesses
▪adverse changes in social, political, economic or market conditions or the stability of foreign governments
▪adverse
rulings by foreign courts or tribunals; challenges to or difficulty obtaining, maintaining and complying with permits or approvals; difficulty enforcing contractual and property rights; differing legal standards for lawsuits or other proceedings; and unsettled property rights and titles in Mexico
▪expropriation or theft of assets
▪with respect to our non-utility international business activities, changes in the priorities and budgets of international customers, which may be driven by many of the factors listed above, among others
Mexican Government Influence on Economic and Energy Matters
The Mexican government exercises significant and increasing influence over the Mexican economy and energy sector and has adopted or proposed additional
changes that, in each case, could fundamentally impact private investment in this sector.
Mexican governmental actions in the past several years in the electricity market include resolutions, orders, decrees, regulations and proposed and adopted amendments to Mexican law that could, among other things, threaten the prospects for private-party renewable energy generation in the country, limit the ability to dispatch renewable energy and receive or maintain operational permits, and increase costs of electricity for legacy renewables and cogeneration energy contract holders. The President of Mexico also proposed constitutional reform in September 2021 that would have eliminated the wholesale electricity market in Mexico and significantly limited the ability of private parties to participate in electricity generation. Although the proposed constitutional reform did not reach the two-third majority required for its approval and
was therefore rejected by Mexico’s Chamber of Deputies, other similar reforms to centralize and de-privatize the electricity market in Mexico could be proposed in the future.
With respect to midstream and downstream activities, amendments to Mexico’s Hydrocarbons Law that give SENER and the CRE additional powers to suspend and revoke permits became effective in May 2021. The amendments provide that suspension of permits will be determined by SENER or the CRE when a danger to national security, energy security, or the national economy is foreseen, and also provide new grounds for the revocation of permits under certain other circumstances related to a permit holder’s use of illegally imported products, failure to comply with provisions applicable to quantity, quality and measurement of products, or unauthorized
modification of the technical condition of its infrastructure. Additionally, the amendments direct authorities to revoke permits that fail to comply with certain minimum storage and other requirements or violate provisions established by SENER or the amended Hydrocarbons Law, as applicable.
We discuss these Mexican governmental actions in Note 16 of the Notes to Consolidated Financial Statements. We cannot predict whether proposed governmental actions will ultimately be passed or otherwise become effective in their current forms, nor can we predict the nature or level of their impact on the various segments of the energy sector in which we participate. We also cannot predict whether pending actions to enjoin enforcement or suspend or overturn existing laws and other governmental actions will be successful. More generally, we cannot predict the impact that the political, social and judicial landscape in Mexico will have on that
country’s economy and energy sector and our business in Mexico. If any of the proposed governmental actions are passed or otherwise become effective, if efforts to enjoin enforcement or suspend or overturn adopted governmental actions fail, or if other similar moves by the Mexican government are taken to curb private-party participation in the energy sector, including through further amendments to Mexican laws, rules or the constitution or increased investigative and enforcement activities, it may impact our ability to operate our facilities at existing levels or at all, may result in increased costs for Sempra Infrastructure and its customers, may adversely affect our ability to develop new projects, may result in decreased revenues and cash flows, and may
negatively impact our ability to recover the carrying values of our investments in Mexico, any of which may have a material adverse effect on our business, results of operations, financial condition, cash flows and/or prospects.
U.S. and Mexican Laws and Foreign Policy, including Trade and Related Matters
Our international business activities are subject to U.S. and Mexican laws and regulations related to foreign operations or doing business internationally, including the U.S. Foreign Corrupt Practices Act, the Mexican Federal Anticorruption Law in Public Contracting (Ley Federal Anticorrupción en Contrataciones Públicas) and similar laws, and are sensitive to U.S. and Mexican foreign
policy, trade policy and other geopolitical factors. The current and the last U.S. Administrations have taken different stances with respect to international trade agreements, tariffs, immigration policy and other matters of foreign policy that impact trade and foreign relations. Shifts in foreign policy could result in or increase adverse effects on our businesses and create uncertainty, making it difficult to predict the impact these policies could have on our businesses. Violations or alleged violations of the laws referred to above, as well as foreign policy positions that adversely affect imports and exports between the U.S., Mexican and other economies and foreign companies with whom we conduct business, could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
Our businesses are subject to various legal actions challenging our property rights and permits, and our
properties in Mexico could be subject to expropriation by the Mexican government.
We are engaged in disputes regarding our title to the property in Mexico where our ECA Regas Facility is situated and our ECA LNG projects under construction and in development are expected to be situated, which we discuss in Note 16 of the Notes to Consolidated Financial Statements. In addition, we may have or seek to obtain long-term leases or rights-of-way from governmental agencies or other third parties to operate our energy infrastructure on land we do not own. In addition to the risks associated with such property ownership and use that we describe above under “Risks Related to All Sempra Businesses – Operational Risks,” disputes regarding any of these properties could lead to difficulties finding or maintaining suitable partners, customers and project financing arrangements and could hinder or halt our ability to construct and,
if completed, operate the affected facilities or proposed projects. Any of these outcomes could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.
Sempra Infrastructure’s energy infrastructure assets may be considered by the Mexican government to be a public service or essential for the provision of a public service, in which case these assets and the related businesses could be subject to expropriation or nationalization, loss of concessions, renegotiation or annulment of existing contracts, and other similar risks. Any such occurrence could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We own or lease land, warehouses, offices, operating and maintenance centers, shops and service facilities necessary to conduct our businesses. Each of our operating
segments currently has adequate space and, if we need more space, we believe it is readily available. We discuss properties related to our electric, natural gas and energy infrastructure operations in “Part I – Item 1. Business” and Note 1 of the Notes to Consolidated Financial Statements.
ITEM 3.
LEGAL PROCEEDINGS
We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters described in Notes 15 and 16 of the Notes to Consolidated Financial Statements, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A.”
ITEM
5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MARKET INFORMATION
Sempra Common Stock
Our common stock is traded on the NYSE under the trading symbol SRE and the Mexican Stock Exchange under the trading symbol SRE.MX. At February 21, 2023, there were approximately 21,229 record holders of our common stock. Information concerning dividend declarations for Sempra is included in “Part II – Item 7. MD&A – Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”
SoCalGas and SDG&E Common Stock
Information concerning dividend declarations for SoCalGas and SDG&E is included in “Part II – Item 7. MD&A
– Capital Resources and Liquidity – Sources and Uses of Cash – Dividends.”
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
On July 6, 2020, our board of directors authorized the repurchase of shares of our common stock at any time and from time to time in an aggregate amount not to exceed the lesser of $2 billion or amounts spent to purchase no more than 25 million shares. This repurchase authorization was publicly announced on August 5, 2020 and has no expiration date. As of February 28, 2023, a maximum of $1.25 billion and no more than 19,632,529 shares may yet be purchased under this repurchase 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. (RESERVED)
Not
applicable.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Our 2022 operational and financial results reflect our mission to be North America’s premier energy infrastructure company. Key events in 2022 include:
▪SDG&E and SoCalGas filed their 2024 GRC applications and a CPUC proposed decision is scheduled for the second quarter of 2024
▪SDG&E and SoCalGas
received final decisions from the CPUC on their cost of capital for 2023 through 2025, and SDG&E received a final decision on its cost of capital for 2022
▪SoCalGas made significant progress to substantially resolve legal and regulatory matters pertaining to the Leak
▪Oncor filed its comprehensive base rate review and expects to receive a final order from the PUCT around the end of the first quarter of 2023
▪Sempra Infrastructure completed the sale of a 10% NCI in SI Partners to ADIA
▪Sempra Infrastructure advanced development of the PA LNG projects and Cameron LNG Phase 2 project and expects to make a final investment decision for the PA LNG Phase 1 project in the first
quarter of 2023
▪We invested $5.7 billion in capital expenditures and investments
▪We completed $450 million of common stock repurchases pursuant to ASR programs
Our former South American businesses and certain activities associated with those businesses are presented as discontinued operations. Nominal activities that are not classified as discontinued operations have been subsumed into Parent and other. We completed the sales of these businesses in the second quarter of 2020.
RESULTS OF OPERATIONS
We discuss the following in Results of Operations:
▪Overall
results of operations of Sempra;
▪Segment results;
▪Significant changes in revenues, costs and earnings; and
▪Impact of foreign currency and inflation rates on results of operations.
(Dollars and shares
in millions, except per share amounts)
Our earnings and diluted EPS were impacted by variances discussed below in “Segment Results.”
SEGMENT
RESULTS
This section presents earnings (losses) by Sempra segment, as well as Parent and other and discontinued operations, and a related discussion of the changes in segment earnings (losses). Throughout the MD&A, our reference to earnings represents earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted, and before foreign currency and inflation effects and NCI, where applicable.
(1)Includes intercompany eliminations recorded in consolidation
and certain corporate costs.
SDG&E
The increase in earnings of $96 million (12%) in 2022 compared to 2021 was primarily due to:
▪$56 million higher CPUC base operating margin, net of operating expenses;
▪$26 million lower income tax expense primarily from flow-through items, net of lower associated regulatory revenues;
▪$20 million higher income tax benefit from the resolution of prior year income tax items;
▪$9 million higher net regulatory interest income; and
▪$7
million higher AFUDC equity; offset by
▪$26 million higher net interest expense.
SoCalGas
Earnings of $599 million in 2022 compared to losses of $427 million in 2021 was primarily due to:
▪$949 million decrease in charges relating to litigation and regulatory matters pertaining to the Leak comprised of $199 million in 2022 compared to $1,148 million in 2021;
▪$105 million higher CPUC base operating margin, net of operating expenses;
▪$7 million higher AFUDC equity; and
▪$6 million higher
net regulatory interest income; offset by
▪$26 million higher net interest expense; and
▪$10 million in penalties related to the energy efficiency and advocacy OSCs, which we discuss in Note 4 of the Notes to Consolidated Financial Statements.
Sempra Texas Utilities
The increase in earnings of $120 million (19%) in 2022 compared to 2021 was primarily due to higher equity earnings from Oncor Holdings driven by:
▪higher revenues from rate updates to reflect increases in invested capital, higher customer consumption attributable primarily to weather, and customer growth; offset by
▪higher
depreciation expense and interest expense attributable to invested capital; and
▪higher O&M.
Sempra Infrastructure
The decrease in earnings of $372 million in 2022 compared to 2021 was primarily due to:
▪$283 million losses in 2022 compared to $148 million earnings in 2021 from asset and supply optimization driven by higher unrealized losses on commodity derivatives due to changes in natural gas prices, offset by higher diversion revenues;
▪$169 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, net of foreign currency derivative effects, comprised of a $216 million unfavorable impact in 2022 compared
to a $47 million unfavorable impact in 2021; and
▪$13 million selling profit on a sales-type lease relating to the commencement of a rail facility lease at the Veracruz terminal in 2021; offset by
▪$79 million higher equity earnings from Cameron LNG JV primarily from higher revenues from excess LNG production and maintenance revenues;
▪$50
million higher net income tax benefit primarily from the remeasurement of certain deferred income taxes and outside basis differences in JV investments;
▪$50 million lower net interest expense, including $37 million in charges associated with hedge termination costs and a write-off of unamortized debt issuance costs from the early redemptions of debt in October 2021 and $27 million net unrealized gains in 2022 on a contingent interest rate swap related to the proposed PA LNG Phase 1 project that we discuss in Note 11 of the Notes to Consolidated Financial Statements;
▪$42 million higher earnings from the transportation business in Mexico driven by higher rates and higher equity earnings at IMG excluding unfavorable impact from foreign currency and inflation;
▪$14
million higher earnings due to the start of commercial operations of the Veracruz and Mexico City terminals in March and July of 2021, respectively, and remeasurement of operating leases;
▪$12 million higher earnings from the renewables business due to Border Solar and the second phase of ESJ being placed in service in March 2021 and January 2022, respectively; and
▪$10 million higher earnings from TdM driven by higher power prices offset by lower volumes.
Parent and Other
The increase in losses of $30 million (7%) in 2022 compared to 2021 was primarily due to:
▪$120 million deferred income tax expense associated with the change in our indefinite reinvestment
assertion related to our foreign subsidiaries, which we discuss in Note 8 of the Notes to Consolidated Financial Statements;
▪$50 million net investment losses in 2022 compared to $29 million net investment gains in 2021 on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation obligations;
▪$50 million equity earnings in 2021 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs; and
▪$26 million gain on the sale of PXiSE in December 2021; offset by
▪$92 million in charges associated with make-whole premiums and a write-off of unamortized discount and debt
issuance costs from the early redemptions of debt in December 2021;
▪$72 million net income tax expense related to the utilization of a deferred income tax asset upon completing the sale of a 20% NCI in SI Partners to KKR in October 2021;
▪$49 million income tax benefit in 2022 compared to $9 million income tax expense in 2021 from changes to a valuation allowance against certain tax credit carryforwards; and
▪$19 million lower preferred dividends due to the mandatory conversion of all series B preferred stock in July 2021.
SIGNIFICANT CHANGES IN REVENUES, COSTS AND EARNINGS
This
section contains a discussion of the differences between periods in the specific line items of the Consolidated Statements of Operations for Sempra, SDG&E and SoCalGas.
Utilities Revenues and Cost of Sales
Our utilities revenues include natural gas revenues at SoCalGas and SDG&E and Sempra Infrastructure’s Ecogas and electric revenues at SDG&E. Intercompany revenues included in the separate revenues of each utility are eliminated in Sempra’s Consolidated Statements of Operations.
SoCalGas and SDG&E currently operate under a regulatory framework that permits:
▪The cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred
and without markup. The GCIM provides for SoCalGas to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between core customers and SoCalGas. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements.
▪SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered or refunded in subsequent periods through rates.
▪SoCalGas and SDG&E
to recover certain program expenditures and other costs authorized by the CPUC, or “refundable programs.”
Because changes in SoCalGas’ and SDG&E’s cost of natural gas and/or electricity are recovered in rates, changes in these costs
are offset in the changes in revenues and therefore do not impact earnings, other than potential impacts related to the GCIM for SoCalGas that we describe above. In
addition to the changes in cost or market prices, natural gas or electric revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized amounts. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 4 of the Notes to Consolidated Financial Statements.
The table below summarizes utilities revenues and cost of sales.
(1) Excludes depreciation and amortization, which are presented separately on the Sempra, SDG&E and SoCalGas Consolidated Statements of Operations.
Natural Gas Revenues and Cost of Natural Gas
The table below summarizes the average cost of natural
gas sold by Sempra California and included in cost of natural gas. The average cost of natural gas sold at each utility is impacted by market prices, as well as transportation, tariff and other charges.
◦$69 million higher revenues from incremental and balanced capital projects, and
◦$35 million higher revenues associated with impacts resulting from changes in tax laws tracked in the income tax expense memorandum account; and
▪$205 million increase at SDG&E, which included:
◦$121 million increase in cost of natural gas sold, which we discuss below,
◦$35 million higher recovery of costs associated with refundable programs,
which revenues are offset in O&M,
◦$31 million higher revenues from balanced capital projects, and
◦$10 million higher CPUC-authorized revenues.
Our cost of natural gas increased by $1.0 billion to $2.6 billion in 2022 compared to 2021 primarily due to:
▪$864 million increase at SoCalGas primarily due to higher average natural gas prices; and
▪$121 million increase at SDG&E primarily due to higher average natural gas prices.
Electric Revenues and Cost of Electric Fuel and Purchased Power
In 2022 compared to
2021, our electric revenues, substantially all of which are at SDG&E, increased by $125 million (3%) to $4.8 billion primarily due to:
▪$70 million higher CPUC-authorized revenues;
▪$68 million higher revenues associated with SDG&E’s wildfire mitigation plan;
▪$35 million higher recovery of costs associated with refundable programs, which revenues are offset in O&M;
▪$19 million higher revenues from transmission operations; and
▪$14 million higher revenues associated with lower income tax benefits from flow-through items; offset by
▪$75
million lower cost of electric fuel and purchased power, which we discuss below.
Our utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to the California ISO. Our cost of electric fuel and purchased power decreased by $73 million (7%) to $937 million in 2022 compared to 2021 primarily due to $75 million at SDG&E from higher sales to the California ISO due to higher market prices offset by higher purchased power from the California ISO due to higher market prices, net of lower customer demand due to departing load now served by CCAs, and higher utility-owned generation costs.
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 Sempra’s Consolidated Statements of Operations.
In
2022 compared to 2021, revenues from our energy-related businesses decreased by $78 million (4%) to $1.8 billion primarily due to:
▪$344 million decrease in revenues from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
◦$498 million lower revenues primarily driven by $639 million from higher unrealized losses on commodity derivatives offset by $148 million from higher natural gas prices and volumes, offset by
◦$83 million higher diversion fees due to higher natural gas prices, and
▪$143 million higher revenues from TdM mainly due to higher power prices offset by lower volumes from scheduled major maintenance completed in March 2022, which resulted in increased plant reliability;
▪$53 million higher transportation revenues driven by higher rates;
▪$46 million higher revenues from the renewables business due to Border Solar and the second phase of ESJ being placed in service in March 2021 and January 2022, respectively, the acquisition
of ESJ in March 2021 and higher transmission rates; and
▪$5 million higher revenues from the Veracruz and Mexico City terminals placed in service in March and July of 2021, respectively, offset by an $18 million selling profit on a sales-type lease relating to the commencement of a rail facility lease at the Veracruz terminal in the third quarter of 2021 and a remeasurement of an operating lease.
The cost of sales for our energy-related businesses increased by $331 million to $942 million in 2022 compared to 2021 primarily due to higher natural gas prices and higher LNG purchases related to asset and supply optimization and higher prices offset by lower volumes from scheduled major maintenance completed in March 2022 at TdM.
(1) Includes eliminations of intercompany activity.
Our O&M increased by $405 million (9%) to $4.7 billion in 2022 compared to 2021 primarily due to:
▪$222 million increase at
SoCalGas due to:
◦$202 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue, and
◦$20 million higher non-refundable operating costs; and
▪$106 million increase at Sempra Infrastructure due to:
◦$28 million at the transportation business due to maintenance on pipelines and new compressor stations and higher administrative costs,
◦$28 million higher development costs and purchased services,
◦$20 million from the renewables business primarily due to construction repairs and maintenance
at Ventika,
◦$19 million due to the start of commercial operations of the Veracruz and Mexico City terminals in March and July of 2021, respectively, and
◦$10 million higher operating costs at TdM from higher purchased materials and services due to scheduled major maintenance completed in March 2022, offset by
◦$16 million lower operating cost due to remeasurement of operating leases at the refined products terminals; and
▪$90 million increase at SDG&E due to:
◦$70 million higher expenses associated with refundable programs, which costs incurred are recovered in revenue,
and
◦$20 million higher non-refundable operating costs; offset by
▪$13 million decrease at Parent and other primarily from deferred compensation benefit in 2022 compared to an expense in 2021.
Aliso Canyon Litigation and Regulatory Matters
SoCalGas recorded charges of $259 million and $1,593 million in 2022 and 2021, respectively, relating to litigation and regulatory matters pertaining to the Leak. We describe these charges in Note 16 of the Notes to Consolidated Financial Statements.
In 2021, Parent and other recognized a $36 million gain on the sale of PXiSE, which we discuss in Note 5 of the Notes to Consolidated Financial Statements.
Other Income (Expense), Net
As part of our central risk management function, we may enter into foreign currency derivatives to hedge SI Partners’ exposure to movements in the Mexican peso from its controlling interest in IEnova. The gains/losses associated with these derivatives are included in other income (expense), net, as described below, and partially mitigate the transactional effects of foreign currency and inflation included in income tax expense for
SI Partners’ consolidated entities and in equity earnings for SI Partners’ equity method investments. We discuss policies governing our risk management below in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Other income (expense), net, decreased by $34 million to $24 million compared to the same period in 2021 primarily due to:
▪$42 million investment losses in 2022 compared to $50 million investment gains in 2021 on dedicated assets in support of our executive retirement and deferred compensation plans; and
▪$10 million in penalties at SoCalGas in 2022 related to the energy efficiency and advocacy OSCs; offset by
▪$33 million lower net
losses from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions, including:
◦$12 million gains in 2022 on cross-currency swaps compared to $28 million losses in 2021 on foreign currency derivatives and cross-currency swaps as a result of fluctuation of the Mexican peso, and
◦$12 million lower foreign currency losses on a Mexican peso-denominated loan to IMG, which is offset in equity earnings, offset by
◦$13 million losses in 2022 compared to $5 million net gains in 2021 on other foreign currency transactional effects;
▪$20 million higher net interest income on regulatory balancing accounts at SDG&E
and SoCalGas;
▪$10 million higher AFUDC equity, including $7 million at both SDG&E and SoCalGas;
▪$8 million lower non-service component of net periodic benefit cost; and
▪$5 million reversal of penalties in 2021 related to an OII related to SoCalGas’ billing practices.
We provide further details of the components of other income (expense), net, in Note 1 of the Notes to Consolidated Financial Statements.
Interest Expense
Interest expense decreased by $144 million (12%) to $1.1 billion in 2022 compared to 2021 primarily due to:
▪$121 million
decrease at Parent and other primarily due to $126 million in charges associated with make-whole premiums and a write-off of unamortized discount and debt issuance costs from the early redemptions of debt in December 2021, offset by higher debt balances from debt issuances;
▪$101 million decrease at Sempra Infrastructure primarily due to:
◦$54 million in charges associated with hedge termination costs and a write-off of unamortized debt issuance costs from the early redemptions of debt in October 2021, and
◦$33 million net unrealized gains in 2022 on a contingent interest rate swap related to the proposed PA LNG Phase 1 project that we discuss in Note 11 of the Notes to Consolidated Financial Statements; offset by
▪$41
million increase at SoCalGas primarily from higher debt balances from debt issuances; and
▪$37 million increase at SDG&E from higher debt balances from debt issuances.
Income from continuing operations before income taxes and equity earnings
$
1,343
$
219
$
1,489
Equity
earnings, before income tax(1)
666
614
294
Pretax income
$
2,009
$
833
$
1,783
Effective
income tax rate
28
%
12
%
14
%
SDG&E:
Income tax expense
$
182
$
201
$
190
Income
before income taxes
$
1,097
$
1,020
$
1,014
Effective income tax rate
17
%
20
%
19
%
SoCalGas:
Income
tax expense (benefit)
$
138
$
(310)
$
96
Income (loss) before income taxes
$
738
$
(736)
$
601
Effective
income tax rate
19
%
42
%
16
%
(1)We discuss how we recognize equity earnings in Note 6 of the Notes to Consolidated Financial Statements.
Sempra
Sempra’s income tax expense increased by $457 million in 2022 compared to 2021 primarily due to:
▪$60
million income tax benefit in 2022 compared to $445 million income tax benefit in 2021 associated with charges relating to litigation and regulatory matters pertaining to the Leak;
▪$169 million income tax expense in 2022 compared to $4 million income tax expense in 2021 from foreign currency and inflation effects on our monetary positions in Mexico and associated derivatives;
▪$120 million deferred income tax expense associated with the change in our indefinite reinvestment assertion related to our foreign subsidiaries, which we discuss in Note 8 of the Notes to Consolidated Financial Statements; and
▪lower income tax benefits from flow-through items; offset by
▪$72
million net income tax expense related to the utilization of a deferred income tax asset upon completing the sale of a 20% NCI in SI Partners to KKR in October 2021;
▪$49 million income tax benefit in 2022 compared to $9 million income tax expense in 2021 from changes to a valuation allowance against certain tax credit carryforwards;
▪$28 million higher net income tax benefit in 2022 from the remeasurement of certain deferred income taxes; and
▪$22 million higher income tax benefit in 2022 from the resolution of prior year income tax items.
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 decreased by $19 million (9%) in 2022 compared to 2021 primarily due to:
▪higher
income tax benefits from flow-through items; and
▪$14 million higher income tax benefit in 2022 from the resolution of prior year income tax items; offset by
▪higher income tax expense from higher pretax income.
SoCalGas
SoCalGas’ $138
million income tax expense in 2022 compared to a $310 million income tax benefit in 2021 was primarily due to:
▪$60 million income tax benefit in 2022 compared to $445 million income tax benefit in 2021 associated with charges relating to litigation and regulatory matters pertaining to the Leak; and
▪ lower income tax benefits from flow-through items.
Equity Earnings
Equity earnings increased by $155 million (12%) to $1.5 billion in 2022 compared to 2021 primarily due to:
▪$118 million higher equity earnings at Oncor Holdings due to higher
revenues from rate updates to reflect increases in invested capital, higher customer consumption attributable primarily to weather, and customer growth, offset by higher depreciation expense and interest expense attributable to invested capital and higher O&M; and
▪$100 million higher equity earnings at Cameron LNG JV primarily due to excess LNG production and maintenance revenues; offset by
▪$50 million equity earnings in 2021 related to our investment in RBS Sempra Commodities to settle pending VAT matters and related legal costs; and
▪$15 million lower equity earnings at IMG due to higher income tax expense and foreign currency effects, including $12 million lower foreign currency gains on IMG’s Mexican peso-denominated
loans from its JV owners, which is fully offset in other income (expense), net, offset by lower interest expense.
Earnings Attributable to Noncontrolling Interests
Earnings attributable to NCI increased by $1 million (1%) to $146 million in 2022 compared to 2021 primarily due to:
▪$120 million increase as a result of a decrease in our ownership interest in SI Partners offset by an increase in our ownership interest in IEnova; offset by
▪$121 million decrease due to a decrease in SI Partners subsidiaries net income.
Preferred Dividends
Preferred dividends decreased by $19 million to $44 million in 2022 compared to 2021 due
to the conversion of all series B preferred stock in July 2021.
IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS
Because our natural gas distribution utility in Mexico, Ecogas, uses its local currency as its functional currency, its revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra’s results of operations. Prior to the sales of our South American businesses in 2020, our operations in South America used their local currency as their functional currency.
Foreign Currency Translation
Any difference in average exchange rates used for the translation
of income statement activity from year to year can cause a variance in Sempra’s comparative results of operations. Changes in our earnings as a result of foreign currency translation rates between years were negligible in 2022 compared to 2021.
Transactional Impacts
Although the financial statements of most of our Mexican subsidiaries and JVs have the U.S. dollar as the functional currency, some transactions may be denominated in the local currency; such transactions are remeasured into U.S. dollars. This remeasurement creates transactional gains and losses that are included in other income (expense), net, for our consolidated entities and in equity earnings for our JVs.
We utilize cross-currency swaps that exchange our Mexican peso-denominated principal and interest payments into the U.S. dollar and swap Mexican fixed interest rates for
U.S. fixed interest rates. The impacts of these cross-currency swaps are offset in OCI and are reclassified from AOCI into earnings through other income (expense), net and interest expense as settlements occur.
Certain of our Mexican pipelines (namely Los Ramones I at IEnova Pipelines and Los Ramones Norte at TAG) generate revenue based on tariffs that are set by government agencies in Mexico, with contracts denominated in Mexican pesos that are indexed to
the
U.S. dollar, adjusted annually for inflation and fluctuation in the exchange rate. The resultant gains and losses from remeasuring the local currency amounts into U.S. dollars and the offsetting settlement of foreign currency forwards and swaps related to these contracts are included in revenues: energy-related businesses or equity earnings.
Income statement activities at our foreign operations and their JVs are also impacted by transactional gains and losses, a summary of which is shown in the table below:
TRANSACTIONAL
(LOSSES) GAINS FROM FOREIGN CURRENCY AND INFLATION EFFECTS AND ASSOCIATED DERIVATIVES
(Dollars in millions)
Total reported amounts
Transactional (losses) gains included in reported amounts
Income from continuing operations, net of income tax
2,285
1,463
2,255
(218)
(48)
8
Income
from discontinued operations, net of income tax
—
—
1,850
—
—
15
Earnings attributable to noncontrolling interests
(146)
(145)
(172)
54
4
(24)
Earnings
attributable to common shares
2,094
1,254
3,764
(164)
(44)
(1)
Foreign Currency Exchange Rate and Inflation Impacts on Income Taxes and Related Hedging Activity
Our Mexican subsidiaries have U.S. dollar-denominated cash balances, receivables, payables and debt
(monetary assets and liabilities) that are affected by Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities, which are significant, denominated in the Mexican peso that must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation may expose us to fluctuations in income tax expense, other income (expense), net, and equity earnings. We may use foreign currency derivatives as a means to help manage exposure to the currency exchange rate on our monetary assets and liabilities, and this derivative activity impacts other income (expense), net. However, we generally do not hedge our deferred income tax assets
and liabilities, which makes us susceptible to volatility in income tax expense caused by exchange rate fluctuations and inflation.
We also utilized foreign currency derivatives in 2020 to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sales of our operations in Peru and Chile in discontinued operations.
CAPITAL
RESOURCES AND LIQUIDITY
OVERVIEW
Sempra
Liquidity
We expect to meet our cash requirements through cash flows from operations, unrestricted cash and cash equivalents, borrowings under or supported by our credit facilities, other incurrences of debt including issuing debt securities and obtaining term loans, distributions from our equity method investments, project financing and funding from minority interest owners. We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:
▪fund contractual and other obligations and otherwise meet liquidity requirements
▪fund capital contribution requirements
▪fund new business or asset acquisitions or start-ups
Sempra,
SDG&E and SoCalGas currently have reasonable access to the money markets and capital markets and are not currently constrained in their ability to borrow money at market rates from commercial banks, under existing revolving credit facilities, through public offerings registered with the SEC, or through private placements of debt supported by our revolving credit facilities in the case of commercial paper. However, our ability to access the money markets and capital markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if changing economic conditions or disruptions to or volatility in the money markets and capital markets worsen. These sources of funding have become less attractive due to the recent rise in both short-term and long-term interest rates. In addition, our financing activities and actions by credit rating agencies, as well as many other factors, could negatively affect the
availability and cost of both short-term and long-term financing. Also, cash flows from operations may be impacted by the timing of commencement and completion, and potentially cost overruns, of large projects and other material events, such as the settlement of material litigation. 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/reliability) and investments in new businesses. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our goal to maintain our investment-grade credit ratings.
Available Funds
Our committed lines of credit
provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each have five-year credit agreements expiring in 2027 and Sempra Infrastructure has a three-year credit agreement expiring in 2024, committed lines of credit expiring in 2023 and 2024, and an uncommitted revolving credit facility expiring in 2023.
(1) Amounts
at Sempra include $92 held in non-U.S. jurisdictions. We discuss repatriation in Note 8 of the Notes to Consolidated Financial Statements.
(2) Available unused credit is the total available on committed and uncommitted lines of credit that we discuss in Note 7 of the Notes to Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding as a reduction to the available unused credit.
Short-Term Borrowings
We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures, acquisitions or start-ups. SDG&E and SoCalGas use short-term debt primarily to meet working capital needs or to help fund event-specific costs, such as
payments made by SoCalGas relating to litigation and regulatory matters pertaining to the Leak. Commercial paper, lines of credit and term loans were our primary sources of short-term debt funding in 2022.
We discuss our short-term debt activities in Note 7 of the Notes to Consolidated Financial Statements and below in “Sources and Uses of Cash.”
The following table shows selected statistics for our commercial paper borrowings.
At December 31,
2022, Sempra expects to make interest payments on long-term debt totaling $17.3 billion, of which $1.0 billion is expected to be paid in 2023 and $16.3 billion is expected to be paid in subsequent years through 2079. At December 31, 2022, SDG&E expects to make interest payments on long-term debt totaling $4.9 billion, of which $298 million is expected to be paid in 2023 and $4.6 billion is expected to be paid in subsequent years through 2052. At December 31, 2022, SoCalGas expects to make interest payments on long-term debt totaling $3.9 billion, of which $255 million is expected to be paid in 2023 and $3.6 billion is expected to be paid in subsequent years through 2052. 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 calculated expected
interest payments for variable-rate obligations based on forecasted rates in effect at December 31, 2022.
We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, and maturities in Note 7 of the Notes to Consolidated Financial Statements.
Credit Ratings
The credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in 2022.
A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in the imposition of financial or other burdensome covenants or a requirement for collateral to be posted in the case of certain financing arrangements, and may materially and adversely affect the market prices of their equity and debt securities, the
rates at which borrowings are made and commercial paper is issued, and the various fees on their outstanding credit facilities. This could make it more costly for Sempra, SDG&E, SoCalGas and Sempra’s other subsidiaries to issue debt securities, to borrow under credit facilities and to raise certain other types of financing. We provide additional information about our credit ratings at Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors.”
Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A+ and A at Moody’s, S&P and Fitch, respectively, at December 31, 2022.
Sempra, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit that may be impacted by each borrower’s credit rating. For example, assuming a one-notch downgrade:
▪If Sempra were to
experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 bps. The commitment fee on available unused credit would also increase 5 bps.
▪If SDG&E were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 5 bps.
▪If SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 bps. The commitment fee on available unused credit would also increase 2.5 bps.
Sempra’s, SDG&E’s and SoCalGas’ credit ratings also may affect their respective credit limits related to derivative instruments, as we discuss
in Note 11 of the Notes to Consolidated Financial Statements.
Loans to/from Affiliates
At December 31, 2022, Sempra had $301 million in loans due to unconsolidated affiliates. In July 2022, a $626 million loan due to Sempra from an unconsolidated affiliate was paid in full, prior to its March 2023 maturity date.
Postretirement Benefits
Sempra, SDG&E and SoCalGas have significant investments in several trusts to provide for future payments of pensions and PBOP. The trusts’ ability to make ongoing required benefit payments has not been materially adversely affected by changes in asset values, which are dependent on market
fluctuations, contributions and withdrawals. However, changes in asset values or other factors in future periods, such as changes to discount rates, assumed rates of return, mortality tables and regulations, may impact funding requirements for pension and PBOP plans. Additionally, contributions to our plans are based on our funding policy, which generally limits payments from exceeding plan assets of 110% of the projected benefit obligation, which are subject to maximum income tax deduction limitations. Sempra, SDG&E and SoCalGas expect to contribute $238 million, $54 million and $154 million, respectively, to pension and PBOP plans in 2023 and $1.8 billion, $459 million and $1.1 billion, respectively, in the nine years thereafter. At SDG&E and SoCalGas, funding requirements are generally recoverable in rates. We discuss our employee benefit plans and our expected contributions to those plans in Note 9 of the Notes to Consolidated Financial Statements.
Inflation
Reduction Act
The IRA was signed into law in August 2022. The IRA includes tax credits and other incentives for energy and climate initiatives and introduces a 15% corporate alternative minimum tax on adjusted financial statement income for tax years beginning after December 31, 2022. We continue to assess the impacts of the IRA as the U.S. Department of the Treasury and the IRS issue guidance on tax implementation, and the EPA and DOE issue guidance on energy and climate initiatives. We do not expect the IRA to have a material adverse impact on Sempra’s, SDG&E’s or SoCalGas’ results of operations, financial condition and/or cash flows.
Sempra California
SDG&E’s
and SoCalGas’ operations have historically provided relatively stable earnings and liquidity. Their future performance and liquidity will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature, litigation and the changing energy marketplace, as well as other matters described in this report. SDG&E and SoCalGas expect that the available unused funds from their credit facilities described above, which also supports their commercial paper programs, cash flows from operations, and other incurrences of debt including issuing debt securities and obtaining term loans will continue to be adequate to fund their respective current operations and planned capital expenditures. Additionally, as we discuss below, Sempra elected to make equity contributions to SoCalGas of $800 million in September 2021, $150 million in June 2022 and $500 million in August 2022. These voluntary equity contributions
were intended to assist SoCalGas in maintaining its authorized capital structure. SDG&E and SoCalGas manage their capital structures and pay dividends when appropriate and as approved by their respective boards of directors.
As we discuss in Note 4 of the Notes to Consolidated Financial Statements, changes in balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change between over- and undercollected status, may have a significant impact on cash flows. These changes generally represent the difference between when costs are incurred and when they are ultimately recovered or refunded in rates through billings to customers.
SDG&E and SoCalGas are continuing to monitor the impacts of the COVID-19 pandemic on cash flows and results of operations. Some customers have experienced and continue to experience a diminished ability to pay their electric or gas bills, leading to slower payments and higher levels of nonpayment than has been the case historically. These impacts could become significant and could require modifications to our financing plans.
In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E and SoCalGas implemented certain measures to assist customers, including automatically enrolling residential and small business customers with past-due
balances in long-term repayment plans.
In 2021, SDG&E and SoCalGas applied, on behalf of their customers, for financial assistance from the California Department of Community Services and Development under the 2021 California Arrearage Payment Program, which provided funds of $63 million and $79 million for SDG&E and SoCalGas, respectively. In the first quarter of 2022, SDG&E and SoCalGas received and applied the amounts directly to eligible customer accounts to reduce past due balances. In June 2022, AB 205 was approved establishing, among other things, the 2022 California Arrearage Payment Program. In December 2022, SDG&E and SoCalGas received funding of $51 million and $59 million, respectively, related to this program and, in January 2023, applied the amounts directly to eligible customer accounts to reduce past due balances.
SDG&E
Wildfire
Fund
The carrying value of SDG&E’s Wildfire Fund asset totaled $332 million at December 31, 2022. We describe the Wildfire Legislation and SDG&E’s commitment to make annual shareholder contributions to the Wildfire Fund through 2028 in Note 1 of the Notes to Consolidated Financial Statements.
SDG&E is exposed to the risk that the participating California electric IOUs may incur third-party wildfire costs for which they will seek recovery from the Wildfire Fund with respect to wildfires that have occurred since enactment of the Wildfire Legislation in July 2019. In such a situation, SDG&E may recognize a reduction of its Wildfire Fund asset and record an impairment charge against earnings when available coverage is reduced due to recoverable claims from any of the participating IOUs. PG&E has indicated that it will
seek reimbursement from the Wildfire Fund for losses associated with the Dixie Fire, which burned from July 2021 through October 2021 and was reported to be the largest single wildfire (measured by acres burned) in California history. If any California electric IOU’s equipment is determined to be a cause of a fire, it could have a material adverse effect on SDG&E’s and Sempra’s financial condition and results of operations up to the carrying value of our Wildfire Fund asset, with additional potential material exposure if SDG&E’s equipment is determined to be a cause of a fire. In addition, the Wildfire Fund could be completely exhausted due to fires in the other California electric IOUs’ service territories, by fires in SDG&E’s service territory or by a combination thereof. In the event that the Wildfire Fund is materially diminished, exhausted or terminated, SDG&E will lose the protection afforded by the Wildfire Fund, and as a consequence, a fire in
SDG&E’s service territory could have a material adverse effect on SDG&E’s and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Wildfire Mitigation Cost Recovery Mechanism
In July 2021, SDG&E filed a request with the CPUC to establish an interim cost recovery mechanism that would recover 50% of its costs associated with implementation of its wildfire mitigation plan. The proposed recovery would be incremental to wildfire costs currently authorized in its GRC and subject to reasonableness review. In May 2022, the CPUC issued a final decision denying SDG&E’s request and directing SDG&E to file for the review and recovery of its wildfire mitigation plan costs through its next GRC or a separate application. SDG&E expects to submit separate requests in its GRC for review and recovery of its wildfire mitigation plan costs in mid-2023
for costs incurred from 2019 through 2022 and in mid-2024 for costs incurred in 2023.
SONGS Decommissioning
SDG&E has significant investments in the SONGS NDT to provide for future payments of nuclear decommissioning. The NDT’s ability to make ongoing required payments have not been materially or adversely affected by changes in asset values, which are dependent on market fluctuations, contributions and withdrawals. However, asset values could be materially and adversely affected by future activity in the equity and fixed income markets, and changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions to the estimated total cost associated with retiring the assets. Funding requirements are generally recoverable in rates. We discuss SDG&E’s NDT and its expected SONGS decommissioning
payments in Note 15 of the Notes to Consolidated Financial Statements.
SDG&E has entered into PPAs and tolling agreements that are variable interests in unconsolidated entities. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.
SoCalGas
SoCalGas’
future performance and liquidity may be impacted by the resolution of legal, regulatory and other matters pertaining to 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
Cost Estimate, Insurance and Accounting and Other Impacts. At December 31, 2022, SoCalGas estimates certain costs related to the Leak are $3,486 million (the cost estimate), including $1,279 million of costs recovered from insurance. Other than insurance for directors’ and officers’
liability, we have exhausted all of our insurance for 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. At December 31, 2022, $129 million of the cost estimate is accrued in Reserve for Aliso Canyon Costs and $4 million of the cost estimate is accrued in Deferred Credits and Other on SoCalGas’ and Sempra’s Consolidated Balance Sheets.
Sempra elected to make equity contributions to SoCalGas of $800 million in September 2021, $150 million in June 2022 and $500 million in August 2022. These voluntary equity contributions were intended to assist SoCalGas in maintaining its authorized capital structure. SoCalGas paid $1.79 billion in 2022 related to the settlement of the Individual Plaintiff Litigation. SoCalGas funded the settlement
payment using a combination of equity contributions from Sempra, short-term debt and cash on hand.
Except for the amounts paid or estimated to settle certain legal and regulatory matters, the cost estimate does not include any amounts necessary to resolve the matters that we describe in “Litigation – Unresolved” and “Regulatory Proceedings – Unresolved” in Note 16 of the Notes to Consolidated Financial Statements, threatened litigation, other potential litigation or other costs, in each case to the extent it is not possible to predict at this time the outcome of these actions or reasonably estimate the possible costs or a range of possible costs. Further, we are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued. The costs or losses not included in the cost estimate could be significant.
An adverse outcome
with respect to (i) the litigation described in Note 16 of the Notes to Consolidated Financial Statements under “Litigation – Unresolved,” (ii) threatened or other potential litigation related to the Leak, (iii) the Leak OII that we discuss in Note 16 of the Notes to Consolidated Financial Statements, if approval of the negotiated settlement is not obtained, or (iv) the unresolved proceeding pursuant to the SB 380 OII that we discuss below, could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Natural Gas Storage Operations and Reliability. Natural gas withdrawn from storage is important for service reliability during peak demand periods, including peak electric generation needs in the summer and consumer heating needs in the winter. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility
and an important component of SoCalGas’ delivery system. As a result of the Leak, the CPUC has issued a series of directives to SoCalGas specifying the range of working gas to be maintained in the Aliso Canyon natural gas storage facility as well as protocols for the withdrawal of gas, to support safe and reliable natural gas service. In February 2017, the CPUC opened a proceeding pursuant to the SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, including considering alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated.
At December 31, 2022, the Aliso Canyon natural gas storage facility had a net book value of $958 million. If the Aliso Canyon natural gas storage facility were to
be permanently closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we may record an impairment of the facility, which could be material, or we could incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized.
Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the event that Oncor fails to meet its capital requirements, access sufficient capital, or raise capital on favorable terms to finance its ongoing needs, we may elect to make additional capital contributions to Oncor (as our commitments to the PUCT prohibit us from making loans to Oncor), which could be substantial and reduce the cash available to us for other purposes, increase our indebtedness and ultimately materially adversely affect our results of operations, financial condition, cash flows and/or prospects. Oncor’s ability to make distributions may be limited by factors such as its credit ratings, regulatory capital requirements, increases in its capital plan, debt-to-equity ratio approved by the PUCT and other restrictions and considerations. In addition, Oncor will not make distributions if a majority
of Oncor’s independent directors or any minority member director determines it is in the best interests of Oncor to retain such amounts to meet expected future requirements.
Off-Balance Sheet Arrangement
Our investment in Oncor Holdings is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.
Sempra Infrastructure
Sempra Infrastructure expects to fund capital expenditures, investments and operations in part with available funds, including credit facilities, and cash flows from operations of the Sempra Infrastructure businesses. We expect Sempra Infrastructure will require additional funding
for the development and expansion of its portfolio of projects, which may be financed through a combination of funding from the parent and minority interest owners, bank financing, issuances of debt, project financing and partnering in JVs. We describe Sempra Infrastructure’s commitments related to construction and development projects in Note 16 of the Notes to Consolidated Financial Statements.
In June 2022, we completed the sale of a 10% NCI in SI Partners to ADIA for cash proceeds of $1.7 billion. We used a portion of the proceeds from the sale to ADIA to repay commercial paper borrowings used to repurchase $750 million in shares of our common stock ($300 million of which was completed in the fourth quarter of 2021, $200 million of which was completed in the first quarter of 2022 and $250 million of which was completed in the second quarter of 2022), and we used the remaining proceeds to help fund capital expenditures
at Sempra California and Sempra Texas Utilities and to further strengthen our balance sheet.
Following the closing of the ADIA transaction, Sempra, KKR and ADIA directly or indirectly own a 70%, 20%, and 10% interest, respectively, in SI Partners. The sale of NCI in SI Partners to ADIA has reduced our ownership interest in SI Partners and requires us to involve a new minority partner in making certain business decisions. Moreover, the decrease in our ownership of SI Partners also decreases our share of the cash flows, profits and other benefits these businesses currently or may in the future produce.
In 2022, SI Partners distributed $237 million to its minority shareholders.
LNG and Net-Zero Solutions
Cameron LNG Phase 2 Project. Cameron LNG JV is developing a proposed expansion
project that would add one liquefaction train with an expected maximum production capacity of approximately 6.75 Mtpa and would increase the production capacity of the existing three trains at the Cameron LNG Phase 1 facility by up to approximately 1 Mtpa through debottlenecking activities. The Cameron LNG JV site can accommodate additional trains beyond the proposed Cameron LNG Phase 2 project.
Cameron LNG JV previously received major permits and FTA and non-FTA approvals associated with the potential expansion that included up to two additional liquefaction trains and up to two additional full containment LNG storage tanks. In January 2022, Cameron LNG JV filed an amendment, subject to approval by the FERC, to modify the permits to allow the use of electric drives, instead of gas turbine drives, which would reduce overall emissions. The amendment, if approved, would also change the design from a two-train gas turbine expansion
to a one-train electric drive expansion along with other design enhancements that, together, are expected to result in a more cost-effective and efficient facility, while also reducing overall GHG emissions.
Sempra Infrastructure and the other Cameron LNG JV members, namely affiliates of TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha, have entered into an HOA for the potential development of the Cameron LNG Phase 2 project. The HOA provides a commercial framework for the proposed project, including the contemplated allocation to Sempra Infrastructure of 50.2% of the fourth train production capacity and 25% of the debottlenecking capacity from the project under tolling agreements. The HOA contemplates the remaining capacity to be allocated equally to the existing Cameron LNG Phase 1 facility customers. Sempra Infrastructure
plans to sell the LNG corresponding to its allocated capacity from the proposed Cameron LNG Phase 2 project under long-term
SPAs prior to making a final investment decision. The HOA is a non-binding arrangement. The ultimate participation in and offtake by Sempra Infrastructure, TotalEnergies SE, Mitsui & Co., Ltd. and Japan LNG Investment, LLC remain subject to negotiation and finalization of definitive agreements, among other factors, and the
HOA does not commit any party to enter into definitive agreements with respect to the proposed Cameron LNG Phase 2 project.
Sempra Infrastructure, the other Cameron LNG JV members, and Cameron LNG JV have entered into a Phase 2 Project Development Agreement under which Sempra Infrastructure, subject to certain conditions and ongoing approvals by the Cameron LNG JV board, will manage and lead the Cameron LNG Phase 2 project development work until Cameron LNG JV makes a final investment decision.
Cameron LNG JV, upon the unanimous approval of the Cameron LNG JV board, awarded two FEED contracts, one to Bechtel and the other to a joint venture between JGC America Inc. and Zachry Industrial Inc. At the conclusion of the resulting competitive FEED process, we expect to select one contractor to be the EPC contractor for the proposed Cameron LNG Phase 2 project.
In
connection with the execution of the Phase 2 Project Development Agreement and the award of the FEED contracts, the Cameron LNG JV board unanimously approved an expansion development budget to fund, subject to the terms of the Phase 2 Project Development Agreement, development work necessary to prepare for a potential final investment decision.
Cameron LNG JV has entered into an MOU with Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, to negotiate the terms and conditions for a new electric service agreement intended to reduce Cameron LNG JV’s scope 2 emissions from the electricity it purchases from Entergy Louisiana, LLC. The MOU sets forth a framework for Entergy Louisiana, LLC and Cameron LNG JV to finalize and sign a minimum 20-year agreement for the procurement of new renewable generation resources in Louisiana, subject to the ultimate approval of the Louisiana Public Service Commission and Cameron LNG JV.
The MOU is a non-binding arrangement. The ultimate arrangement between Cameron LNG JV and Entergy Louisiana, LLC remains subject to negotiation and finalization of definitive agreements, among other factors, and the MOU does not commit any party to enter into definitive agreements with respect to the proposed electric services agreement.
Sempra Infrastructure has entered into a non-binding HOA for the negotiation and potential finalization of a definitive 20-year SPA with ORLEN for 2 Mtpa of LNG offtake from the proposed Cameron LNG Phase 2 project. Sempra Infrastructure also entered into a non-binding HOA for the negotiation and potential finalization of definitive SPAs with Williams for two 20-year terms for approximately 3 Mtpa of LNG offtake in the aggregate from the PA LNG Phase 2 project and Cameron LNG Phase 2 project that are under development, and a separate natural gas sales agreement for approximately 0.5 Bcf per
day to be delivered as feed gas supply for the proposed PA LNG projects and Cameron LNG Phase 2 project. In addition, the parties anticipate forming a strategic JV to own, expand and operate the existing Cameron Interstate Pipeline that we expect will deliver natural gas to the proposed Cameron LNG Phase 2 project and the proposed Port Arthur Pipeline Louisiana Connector that we expect will deliver natural gas to the proposed PA LNG projects. The ultimate participation in and offtake from the proposed projects remain subject to negotiation and finalization of definitive agreements, among other factors, and the HOAs do not commit any party to enter into definitive agreements with respect to any of the applicable proposed projects.
Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is subject to certain restrictions and conditions under the JV project financing agreements, including among others, scope
restrictions on expansion of the project unless appropriate prior consent is obtained from the existing project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the partners, including with respect to the equity investment obligation of each partner. Working under the framework established in the Phase 2 Project Development Agreement, Sempra Infrastructure is targeting completing the FEED work in the summer of 2023 and expects to be in a position to make a final investment decision shortly thereafter. The timing of when or if Cameron LNG JV will receive approval from the FERC to amend its permits and from the existing project lenders to conduct the expansion under its financing agreements is uncertain, and there is no assurance that Sempra Infrastructure will complete the necessary development work or that the Cameron LNG JV members will unanimously agree in a timely manner or at all on making a final
investment decision, which, if not accomplished, would materially and adversely impact the development of the Cameron LNG Phase 2 project.
The development of the proposed Cameron LNG Phase 2 project is subject to numerous other risks and uncertainties, including securing binding customer commitments; reaching unanimous agreement with our partners to proceed; obtaining and maintaining a number of permits and regulatory approvals, including approval from the FERC for amendments to existing permits; securing certain consents under the existing financing agreements and securing sufficient new financing; negotiating and completing suitable commercial agreements for the project, including a definitive EPC contract and definitive tolling and governance agreements; reaching a positive final investment decision; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk
Factors.”
ECA LNG Phase 1 Project. SI Partners owns an 83.4% interest in ECA LNG Phase 1, and an affiliate of TotalEnergies SE owns the remaining 16.6% interest. ECA LNG Phase 1 is constructing a one-train natural gas liquefaction facility at the site of Sempra Infrastructure’s existing ECA Regas Facility with a nameplate capacity of 3.25 Mtpa and an initial offtake capacity of 2.5 Mtpa. We do not expect the construction or
operation of the ECA LNG Phase 1 project to disrupt operations at the ECA Regas Facility, and have planned measures to limit disruption of operations should any arise. We expect the ECA LNG Phase 1 project to commence commercial operations in the summer of 2025.
We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the ECA LNG Phase 1 project. ECA LNG Phase 1 has definitive 20-year SPAs with an affiliate of TotalEnergies SE for approximately 1.7 Mtpa of LNG and with Mitsui & Co., Ltd. for approximately 0.8 Mtpa of LNG.
In February 2020, we entered into an EPC contract with Technip Energies for the ECA LNG Phase 1 project. Since reaching a positive final investment decision with respect to the project in November 2020, Technip Energies has been working to construct the ECA LNG Phase 1 project. We estimate
the total price of the EPC contract to be approximately $1.5 billion, with capital expenditures approximating $2.0 billion including capitalized interest and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates.
ECA LNG Phase 1 has a five-year loan agreement with a syndicate of seven external lenders that matures in December 2025 for an aggregate principal amount of up to $1.3 billion, of which $575 million was outstanding at December 31, 2022. 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 is subject to numerous risks and uncertainties,
including maintaining permits and regulatory approvals; construction delays; securing and maintaining commercial arrangements, such as gas supply and transportation agreements; the impact of recent and proposed changes to the law in Mexico; and other factors associated with the project and its construction. 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 could materially adversely affect construction of this project and Sempra’s results of operations, financial condition, cash flows and/or prospects, including the impairment of all or a substantial portion of the capital costs invested in the project to date. For a discussion of these risks, see “Part I – Item 1A. Risk Factors.”
ECA LNG Phase 2 Project. Sempra Infrastructure is developing a second, large-scale natural gas liquefaction
project at the site of its existing ECA Regas Facility. We expect the proposed ECA LNG Phase 2 project to be comprised of two trains and one LNG storage tank and produce approximately 12 Mtpa of export capacity. We expect that construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility, which currently has long-term regasification contracts for 100% of the regasification facility’s capacity through 2028. This makes the decisions on whether, when and how to pursue the proposed ECA LNG Phase 2 project dependent in part on whether the investment in a large-scale liquefaction facility would, over the long term, be more beneficial financially than continuing to supply regasification services under our existing contracts.
We received authorizations from the DOE to export U.S.-produced natural gas to Mexico and to re-export LNG to non-FTA countries from the proposed ECA
LNG Phase 2 project.
We have MOUs and/or HOAs with Mitsui & Co., Ltd., TotalEnergies SE, and ConocoPhillips that provide a framework for their potential offtake of LNG from the proposed ECA LNG Phase 2 project and potential acquisition of an equity interest in ECA LNG Phase 2. These MOUs and HOAs are non-binding arrangements. The ultimate participation in and offtake by these parties remains subject to negotiation and finalization of definitive agreements, among other factors, and the MOUs and HOAs do not commit any party to enter into definitive agreements with respect to the proposed ECA LNG Phase 2 project.
Development of the ECA LNG Phase 2 project is subject to numerous risks and uncertainties, including obtaining binding customer commitments; the receipt of a number of permits and regulatory approvals; obtaining financing; negotiating and completing suitable commercial
agreements, including a definitive EPC contract, equity acquisition and governance agreements, LNG sales agreements and gas supply and transportation agreements; reaching a positive final investment decision; the impact of recent and proposed changes to the law in Mexico; the property disputes and permit challenges that we reference in the ECA LNG Phase 1 project discussion above; and other factors associated with this potential investment.
PA LNG Phase 1 Project. Sempra Infrastructure is developing a proposed natural gas liquefaction project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. We are developing the PA LNG Phase 1 project, which we expect will consist of two liquefaction trains, two LNG storage tanks, a marine berth and associated loading facilities and related infrastructure necessary to provide liquefaction services with
a nameplate capacity of approximately 13 Mtpa and an initial offtake capacity of approximately 10.5 Mtpa.
In April 2019, the FERC approved the siting, construction and operation of the proposed PA LNG Phase 1 project facilities, along with certain natural gas pipelines, including the Port Arthur Pipeline Louisiana Connector and Texas Connector, that could be used to supply feed gas to the liquefaction facility if and when the project is completed.
Sempra Infrastructure received authorizations from the DOE in August 2015 and May 2019 that collectively permit the LNG to be produced from the proposed PA LNG Phase 1 project to be exported to all current and future FTA and non-FTA countries.
Sempra Infrastructure has entered into the following definitive SPAs, each of which is subject to making a positive final investment decision and customary closing conditions, for LNG offtake from the proposed PA LNG Phase 1 project with:
▪ConocoPhillips for a 20-year term for 5 Mtpa of LNG. In addition, the parties entered into an equity purchase and sale agreement whereby ConocoPhillips will acquire a 30% ownership interest in the proposed PA LNG Phase 1 project, and a natural gas supply management agreement whereby ConocoPhillips will manage the feed gas supply requirements for the proposed facility.
▪RWE
Supply & Trading GmbH, a subsidiary of RWE AG, for a 15-year term for 2.25 Mtpa of LNG.
▪INEOS for a 20-year term for approximately 1.4 Mtpa of LNG.
▪ORLEN for a 20-year term for approximately 1 Mtpa of LNG.
▪ENGIE S.A. for a 15-year term for approximately 0.875 Mtpa of LNG.
In February 2020, we entered into an EPC contract with Bechtel for the proposed PA LNG Phase 1 project. We have no obligation to move forward under the EPC contract, and we may release Bechtel to perform portions of the work pursuant to limited notices to proceed. In October 2022, we amended and restated the EPC contract to reflect an estimated price of approximately $10.5 billion, subject to adjustments. The contract price is valid
until May 8, 2023, subject to certain conditions, including timely issuances of limited notices to proceed and price escalations of up to a maximum of $149 million. Sempra Infrastructure and Bechtel must mutually agree to an adjustment to the contract price if the full notice to proceed is issued after May 8, 2023. Any agreement on such an amendment to the EPC contract by both parties or on favorable terms to Sempra Infrastructure cannot be assured. Either party may terminate the EPC contract if the full notice to proceed is not issued by May 8, 2024.
We are progressing the development of the proposed PA LNG Phase 1 project, and are targeting a final investment decision in the first quarter of 2023 taking into account market demands given the current geopolitical environment,
executing definitive agreements for LNG offtake and equity investments, and obtaining financing.
Development of the PA LNG Phase 1 project is subject to a number of risks and uncertainties, including obtaining binding customer commitments; identifying suitable project and equity partners; completing the required commercial agreements, such as equity acquisition and governance agreements and gas supply and transportation agreements; maintaining all necessary permits and approvals; obtaining financing and incentives; reaching a positive final investment decision; and other factors associated with the potential investment. An unfavorable outcome with respect to any of these factors could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects, including the impairment of all or a substantial portion of the capital costs invested in the project to date. For a discussion
of these risks, see “Part I – Item 1A. Risk Factors.”
PA LNG Phase 2 Project. Sempra Infrastructure is developing a second phase of the natural gas liquefaction project that we expect will be a similar size to the proposed PA LNG Phase 1 project. We are progressing the development of the proposed PA LNG Phase 2 project, while continuing to evaluate overall opportunities to develop the entirety of the Port Arthur site as well as potential design changes that could reduce overall emissions, including a facility design utilizing renewable power sourcing and other technological solutions.
In February 2020, Sempra Infrastructure filed an application, subject to approval by the FERC, for the siting, construction and operation of the proposed PA LNG Phase 2 project, including the potential addition of up to two liquefaction trains. Also in February 2020, Sempra
Infrastructure filed an application with the DOE to permit LNG produced from the proposed PA LNG Phase 2 project to be exported to all current and future FTA and non-FTA countries.
Sempra Infrastructure has entered into non-binding HOAs for the negotiation and potential finalization of definitive SPAs with INEOS for approximately 0.2 Mtpa of LNG offtake and with Williams, as we discuss above, for LNG offtake, in each case from the proposed PA LNG Phase 2 project. The ultimate participation in and offtake from the proposed project remains subject to negotiation and finalization of definitive agreements, among other factors, and the HOAs do not commit any party to enter into a definitive agreement with respect to the proposed project.
Development of the PA LNG Phase 2 project is subject to a number of risks and uncertainties, including obtaining binding customer commitments; identifying
suitable project and equity partners; completing the required commercial agreements, such as equity acquisition and governance agreements, LNG sales agreements and gas supply and transportation agreements; securing and
maintaining all necessary permits and approvals, including approval from the FERC; obtaining financing and incentives; reaching a positive final investment decision; and other factors associated with the potential investment. An unfavorable
outcome with respect to any of these factors could have a material adverse effect on Sempra’s results of operations, financial condition, cash flows and/or prospects, including the impairment of all or a substantial portion of the capital costs invested in the project to date. For a discussion of these risks, see “Part I – Item 1A. Risk Factors.”
Vista Pacifico LNG Liquefaction Project. Sempra Infrastructure is developing Vista Pacifico LNG, a potential natural gas liquefaction, storage, and mid-scale export facility proposed to be located in the vicinity of Topolobampo in Sinaloa, Mexico, under an MOU with the CFE, which was subsequently updated in July 2022, that contemplates the negotiation of definitive agreements that would cover development of Vista Pacifico LNG and the re-routing of a portion of the Guaymas-El Oro segment of the Sonora pipeline and resumption of its operations. The proposed
LNG export terminal would be supplied with U.S. natural gas and would use excess natural gas and pipeline capacity on existing pipelines in Mexico with the intent of helping to meet growing demand for natural gas and LNG in the Mexican and Pacific markets.
Sempra Infrastructure received authorization from the DOE to permit the export of U.S.-produced natural gas to Mexico and for LNG produced from the proposed Vista Pacifico LNG facility to be re-exported to all current and future FTA countries in April 2021 and non-FTA countries in December 2022.
In March 2022, TotalEnergies SE and Sempra Infrastructure entered into an MOU that contemplates TotalEnergies SE potentially contracting approximately one-third of the long-term export production of the proposed Vista Pacifico LNG project and potentially participating as a minority partner in the project.
The
MOUs related to the proposed Vista Pacifico LNG project are non-binding arrangements. The ultimate participation in and offtake from the proposed project remain subject to negotiation and finalization of definitive agreements, among other factors, and the MOUs do not commit any party to enter into definitive agreements with respect to the project.
The development of the potential Vista Pacifico LNG project is subject to numerous risks and uncertainties, including securing binding customer commitments; obtaining and maintaining a number of permits and regulatory approvals; securing financing; identifying suitable project partners; negotiating and completing suitable commercial agreements, including definitive EPC contracts, equity acquisition and governance agreements, LNG sales agreements and gas supply and transportation agreements; reaching a positive final investment decision; the impact of recent and proposed changes to
the law in Mexico; and other factors associated with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors.”
Hackberry Carbon Sequestration Project. Sempra Infrastructure is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana. This proposed project under development is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility and the proposed Cameron LNG Phase 2 project. In the third quarter of 2021, Sempra Infrastructure filed an application with the EPA for a Class VI carbon injection well to advance this project.
In May 2022, Sempra Infrastructure, TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation signed a Participation Agreement for the development of the proposed Hackberry Carbon Sequestration project. The Participation Agreement
contemplates that the combined Cameron LNG Phase 1 facility and proposed Cameron LNG Phase 2 project would potentially serve as the anchor source for the capture and sequestration of carbon dioxide by the proposed project. It also provides the basis for the parties to enter into a JV with Sempra Infrastructure for the Hackberry Carbon Sequestration project.
The development of the potential Hackberry Carbon Sequestration project is subject to numerous risks and uncertainties, including obtaining required consents from the Cameron LNG JV members, securing binding customer commitments; identifying suitable project partners; obtaining and maintaining a number of permits and regulatory approvals; securing financing; negotiating and completing suitable commercial agreements, including a definitive EPC contract, and equity acquisition and governance agreements; reaching a positive final investment decision; and other factors associated
with this potential investment. For a discussion of these risks, see “Part I – Item 1A. Risk Factors.”
Asset and Supply Optimization. As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk,” Sempra Infrastructure enters into hedging transactions to help mitigate commodity price risk. Sempra Infrastructure posted net margin of approximately $1.4 billion in 2022 and anticipates that, once the natural gas is sold and derivatives are settled, the previously unrealized gains or losses associated with the economic hedge positions would be realized, with the cash collateral posted largely offset by collections from natural gas sales.
Off-Balance Sheet Arrangements. Our investment in Cameron LNG JV is a variable interest in an unconsolidated entity. We discuss variable interests in Note 1
of the Notes to Consolidated Financial Statements.
In June 2021, Sempra provided a promissory note, which constitutes a guarantee, for the benefit of Cameron LNG JV with a maximum exposure to loss of $165 million. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt,
scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA. We discuss
this guarantee in Note 6 of the Notes to Consolidated Financial Statements.
In July 2020, Sempra entered into a Support Agreement, which contains a guarantee and represents a variable interest, for the benefit of CFIN with a maximum exposure to loss of $979 million. The guarantee will terminate upon full repayment of the guaranteed debt by 2039, including repayment following an event in which the guaranteed debt is put to Sempra. We discuss this guarantee in Notes 1, 6 and 9 of the Notes to Consolidated Financial Statements.
Energy Networks
Construction Projects. In 2022, Sempra Infrastructure completed construction of a terminal for the receipt, storage, and delivery of refined products in the vicinity of Puebla. Sempra Infrastructure is also developing terminals for the receipt, storage, and delivery of refined
products in the vicinity of Manzanillo and Ensenada.
As part of an industrywide audit and investigative process initiated by the CRE to enforce fuel procurement laws, federal prosecutors conducted inspections at several refined products terminals, including Sempra Infrastructure’s refined products terminal in Puebla, to confirm that the gasoline and/or diesel in storage were legally imported. During the inspection of the Puebla terminal in September 2021, a federal prosecutor took samples from all the train and storage tanks in the terminal and ordered that the facility be temporarily shut down during the pendency of the analysis of the samples and investigation, while leaving the terminal in Sempra Infrastructure’s custody. In November 2021, the CRE notified Sempra Infrastructure that it had started a process to revoke Sempra Infrastructure’s storage permit at the Puebla terminal. In December 2021, Sempra Infrastructure filed
its response to the CRE. In May 2022, the CRE provided a final resolution that stopped the permit revocation process. In August 2022, the federal prosecutor concluded the investigation and lifted the order that had temporarily shut down the facility. Commissioning activities were restarted, and commercial operations commenced in October 2022.
Construction of the Topolobampo terminal was substantially completed in May 2022, at which time commissioning activities commenced. Subject to the receipt of pending permits, we expect the Topolobampo terminal will commence commercial operations in the first half of 2023.
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.”
Clean Power
Construction
Projects. ESJ completed construction and began commercial operations of a second, 108-MW wind power generation facility in January 2022. This second wind power generation facility is fully contracted by SDG&E under a long-term PPA expiring in 2042.
Legal and Regulatory Matters
See Note 16 of the Notes to Consolidated Financial Statements and “Part I – Item 1A. Risk Factors” for discussions of the following legal and regulatory matters affecting our operations in Mexico:
One or more unfavorable final decisions on these land disputes or environmental and social impact permit challenges could materially adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the site of the ECA Regas Facility and have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Our investment in the Guaymas-El Oro segment of the Sonora pipeline could be subject to impairment if Sempra Infrastructure and the CFE are unable to re-route a portion of the pipeline (which has
not been agreed to by the parties, but is subject to negotiation pursuant to a non-binding MOU and a Shareholders’ Agreement with the CFE that remains subject to regulatory and corporate authorizations) and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery. Any such occurrence could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Sempra Infrastructure and other parties affected by these amendments to Mexican law have challenged them by filing amparo and other claims, some of which remain pending. An unfavorable decision on one or more of these amparo or other challenges, the impact of the amendments
that have become effective (due to unsuccessful amparo challenges or otherwise), or the possibility of future reforms to the energy industry through additional amendments to Mexican laws, regulations or rules (including through amendments to the constitution) may impact our ability to operate our facilities at existing levels or at all, may result in increased costs for Sempra Infrastructure and its customers, may adversely affect our ability to develop new projects, may result in decreased revenues and cash flows, and may negatively impact our ability to recover the carrying values of our investments in Mexico, any of which may have a material adverse effect on our business, results of operations, financial condition, cash flows and/or prospects.
We invest the majority of our capital expenditures in Sempra California, primarily for transmission and distribution improvements, including pipeline and wildfire safety. The following table summarizes by segment capital expenditures for the last three years.
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 2023, we expect to make capital expenditures and investments of approximately $5.7 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 2023 will relate to transmission and distribution improvements at our regulated public utilities, and construction of the ECA LNG Phase 1 liquefaction project and natural gas pipelines at Sempra Infrastructure.
From 2023 through 2026, and subject to the factors described below, which could cause these estimates to vary substantially, Sempra expects to make aggregate capital expenditures and investments of approximately $18.7 billion (which excludes capital expenditures that will be funded by unconsolidated entities), as follows: $8.9 billion at SDG&E, $7.8 billion at SoCalGas, $0.8 billion at Sempra Texas Utilities and $1.2 billion at Sempra Infrastructure. Capital expenditure amounts include capitalized interest and AFUDC related to debt.
Periodically, we review our construction, investment and financing programs
and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, and safety and environmental requirements.
Our level of capital expenditures and investments in the next few years may vary substantially and will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in U.S. federal tax law and business
opportunities providing desirable rates of return. See “Part I – Item 1A. Risk Factors” for a discussion of other factors that could affect future levels of our capital expenditures and investments. We intend to finance our capital expenditures in a manner that will maintain our investment-grade credit ratings and capital structure, but there is no guarantee that we will be able to do so.
Weighted-Average Rate Base
Rate base is the value of assets on which SDG&E and SoCalGas are permitted to earn a specified rate of return in accordance with rules set by regulatory agencies, including the CPUC and the FERC (for SDG&E), which is calculated using a 13-month average in accordance with CPUC methodology as adopted in rate-setting proceedings. The following
table summarizes the weighted-average rate base for SDG&E and SoCalGas for the last three years.
WEIGHTED-AVERAGE RATE BASE
(Dollars in millions)
2022
2021
2020
SDG&E
$
13,780
$
12,527
$
11,109
SoCalGas
10,494
9,371
8,228
The
increase in weighted-average rate base reflects the significant capital investments that SDG&E and SoCalGas have made in transmission and distribution safety and reliability. We expect the weighted-average rate base to continue to increase in 2023 based on our expected capital investments.
Capital Stock Transactions
Sempra
Cash provided by issuances of common and preferred stock was:
▪$4 million in 2022
▪$5 million in 2021
▪$902 million in 2020
Cash
used for repurchases of common stock was:
▪$478 million in 2022
▪$339 million in 2021
▪$566 million in 2020
Sempra Common Stock Repurchases. As we discuss in Note 14 of the Notes to Consolidated Financial Statements, we repurchased 1,472,756 shares of our common stock for $200 million pursuant to an ASR program that was completed in February 2022. We repurchased an additional 1,471,957 shares of our common stock for $250 million pursuant to an ASR program that was completed in April 2022. These share repurchases were funded with commercial paper borrowings that we repaid with a portion of the proceeds received from the sale of NCI in SI Partners to ADIA, which closed in June 2022.
Dividends
Sempra
Sempra paid cash dividends of:
▪$1,430 million for common stock and $44 million for preferred stock in 2022
▪$1,331 million for common stock and $99 million for preferred stock in 2021
▪$1,174 million for common stock and $157 million for preferred stock in 2020
On February 27, 2023, our board of directors declared a
dividend of $1.19 per share on our common stock and a dividend of $24.375 per share on our series C preferred stock, both payable on April 15, 2023.
All declarations of dividends on our common stock and preferred stock are made at the discretion of the board of directors. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend on earnings, cash flows, financial and legal requirements, and other relevant factors at that time. As a result, Sempra’s dividends on common stock and preferred stock declared on a historical basis may not be indicative of future declarations.
SDG&E
In 2022, 2021 and 2020, SDG&E paid common stock dividends to Enova and Enova paid corresponding dividends to Sempra of $100 million, $300 million and
$200 million, respectively. SDG&E’s dividends on common stock declared on an annual historical basis may not be indicative of future declarations and could be impacted over the next few years in order for SDG&E to maintain its authorized capital structure while managing its capital investment program.
Enova, a wholly owned subsidiary of Sempra, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova and dividends paid by Enova to Sempra are eliminated in Sempra’s consolidated financial statements.
SoCalGas
SoCalGas did not declare or pay common stock dividends in 2022. In 2021 and 2020, SoCalGas paid common stock dividends to PE and PE paid corresponding dividends to Sempra of $75 million and $100 million, respectively. SoCalGas’ dividends on common stock declared on an annual historical
basis may not be indicative of future declarations and could be impacted over the next few years in order for SoCalGas to maintain its authorized capital structure.
PE, a wholly owned subsidiary of Sempra, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to PE and dividends paid by PE to Sempra are eliminated in Sempra’s consolidated financial statements.
Dividend Restrictions
The board of directors for each of Sempra, SDG&E and SoCalGas has the discretion to determine whether to declare and, if declared, the amount of any dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra. At December 31, 2022, based on these regulations,
Sempra could have received combined loans and dividends of approximately $504 million from SDG&E and $347 million from SoCalGas. In addition, the terms of Sempra’s series C preferred stock limit Sempra’s ability to declare dividends on its common stock under certain circumstances.
We provide additional information about dividend restrictions in “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements and in Note 13 of the Notes to Consolidated Financial
Statements.
Book Value Per Common Share
Sempra’s book value per common share on the last day of each of the last three fiscal years was as follows:
▪$83.43 in 2022
▪$79.17 in 2021
▪$70.11 in 2020
The increase in 2022 was primarily due to comprehensive income exceeding dividends and a fair value that was higher than carrying value related to the change in ownership, which did not result in a change of control, from the sale of NCI in SI Partners to ADIA. In 2021, the increase was primarily due to
a fair value that was higher than carrying value related to the change in ownership, which did not result in a change of control, from the sale of NCI in SI Partners to KKR, the IEnova exchange offer and subsequent cash tender offer, and the common shares issued from the conversion of series A preferred stock and series B preferred stock.
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 2022 that affected capitalization included the following:
▪Sempra: increase in long-term debt, offset by a decrease in short-term debt and increase in equity primarily from comprehensive income exceeding dividends and the sale of NCI.
▪SDG&E: increase in long-term debt, offset by a decrease in short-term debt and increase in equity
from comprehensive income exceeding dividends.
▪SoCalGas: increase in short-term and long-term debt, offset by an increase in equity from comprehensive income and equity contributions from Sempra.
CRITICAL ACCOUNTING ESTIMATES
Management
views certain accounting estimates as critical because their application is the most relevant, judgmental and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss critical accounting estimates that are material to our financial statements with the Audit Committee of Sempra’s board of directors.
We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and if:
▪information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events
▪the amount of the loss or a range of possible losses can be reasonably estimated
We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.
Actual amounts realized
upon settlement of contingencies may be different than amounts recorded and disclosed and may affect our results of operations, financial condition and cash flows. Details of our issues in this area are discussed in Note 16 of the Notes to Consolidated Financial Statements.
REGULATORY ACCOUNTING
Sempra, SDG&E, SoCalGas
As regulated entities, SDG&E’s and SoCalGas’ customer rates, as set and monitored by regulators, are designed to recover the cost of providing service and to provide the opportunity to realize their authorized rates of return on their investments. SDG&E and SoCalGas assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as:
▪changes
in the regulatory and political environment or the utility’s competitive position
▪issuance of a regulatory commission order
▪passage of new legislation
To the extent that circumstances associated with regulatory balances change, the regulatory balances are evaluated and adjusted if appropriate.
Significant management judgment is required to evaluate the anticipated recovery of regulatory assets and plant investments, the recognition of incentives and revenues subject to refund, as well as the existence and amount of regulatory liabilities. Adverse regulatory or legislative actions could materially impact the amounts of our regulatory assets and liabilities and could materially adversely impact our results of operations and financial
condition. Specifically, if future recovery of costs ceases to be probable, all or part of the associated regulatory assets and/or plant investments would need to be written off against current period earnings, or adverse regulatory or legislative actions could give rise to material new or higher regulatory liabilities. We discuss details of SDG&E’s and SoCalGas’ regulatory assets and liabilities and additional factors that management considers when assessing probabilities associated with regulatory balances in Notes 1, 4, 15 and 16 of the Notes to Consolidated Financial Statements.
INCOME TAXES
Sempra, SDG&E, SoCalGas
Our income tax expense and related balance sheet amounts involve significant management judgments and estimates. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals,
involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. When we evaluate the anticipated resolution of income tax issues, we consider:
▪ past resolutions of the same issue or similar issues
▪ the status of any income tax examination in progress
▪ positions taken by taxing authorities with other taxpayers with similar issues
The likelihood of deferred income tax recovery is based on analyses of the deferred income tax assets and our expectation of future taxable income, based on our strategic planning. Should a change in facts or circumstances lead to a change in judgment about the ultimate realizability of a deferred tax asset, we would record or adjust the related valuation allowance in the period that the
change in facts and circumstances occurs, along with a corresponding increase or decrease in the provision for income taxes.
Actual income taxes could vary from estimated amounts because of:
▪ future impacts of various items, including changes in tax laws, regulations, interpretations and rulings
▪ our financial condition in future periods
▪
the resolution of various income tax issues between us and taxing and regulatory authorities
Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our results of operations, financial condition and cash flows.
We discuss these matters and additional information related to accounting for income taxes, including uncertainty in income taxes, in Note 8 of the Notes to Consolidated Financial Statements.
PENSION AND PBOP PLANS
Sempra, SDG&E, SoCalGas
To measure our pension and PBOP obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions,
including interest rates, in making these assumptions. We review these assumptions annually and update when appropriate.
The critical assumptions used to develop the required estimates include the following key factors:
▪discount rates
▪expected return on plan assets
▪health care cost trend rates
▪interest crediting rate on cash balance accounts
▪mortality rate
▪rate of compensation increases
▪termination
and retirement rates
▪utilization of postretirement welfare benefits
▪payout elections (lump sum or annuity)
▪lump sum interest rates
The actuarial assumptions we use may differ materially from actual results due to:
▪return on plan assets
▪changing market and economic conditions
▪higher or lower withdrawal rates
▪longer or shorter participant life spans
▪more
or fewer lump sum versus annuity payout elections made by plan participants
▪higher or lower retirement rates
Changes in the estimated costs or timing of pension and PBOP, or the assumptions and judgments used by management underlying these estimates (primarily the discount rate and assumed rate of return on plan assets), as well as changes in the circumstances associated with rate recovery, could have a material effect on the recorded expenses and liabilities. The following tables summarize the impact to our projected benefit obligation for pension and accumulated benefit obligation for PBOP at December 31, 2022, and 2022 net periodic benefit costs, in each case if the discount rate or assumed rate of return on plan assets were changed by 100 bps.
(Decrease)
increase to projected benefit obligation,
net
$
(251)
$
279
$
(38)
$
40
$
(198)
$
223
(Decrease) increase to net periodic benefit cost
(16)
23
5
(2)
(21)
25
PBOP:
(Decrease)
increase to accumulated benefit
obligation, net
(69)
85
(13)
16
(54)
67
(Decrease) increase to net periodic benefit cost
(8)
11
(2)
2
(7)
9
IMPACT
DUE TO INCREASE/DECREASE IN RETURN ON PLAN ASSETS
(Dollars in millions)
Sempra
SDG&E
SoCalGas
Increase
Decrease
Increase
Decrease
Increase
Decrease
Pension:
(Decrease)
increase to net periodic benefit cost
$
(29)
$
29
$
(8)
$
8
$
(19)
$
19
PBOP:
(Decrease)
increase to net periodic benefit cost
(14)
14
(2)
2
(11)
11
For SDG&E and SoCalGas plans, the effects of the assumptions on earnings are expected to be recovered in rates and therefore are offset in regulatory accounts. We provide details of our pension and PBOP plans in Note 9 of the Notes to Consolidated Financial Statements.
ASSET RETIREMENT OBLIGATIONS
Sempra,
SDG&E
SDG&E’s legal AROs related to the decommissioning of SONGS are estimated based on a site-specific study performed no less than every three years. The estimate of the obligations includes:
▪ estimated decommissioning costs, including labor, equipment, material and other disposal costs
▪ inflation adjustment applied to estimated cash flows
▪ discount rate based on a credit-adjusted risk-free rate
▪ actual decommissioning costs, progress to date and expected duration of decommissioning activities
SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning
activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s NDT.
SDG&E’s ARO related to the decommissioning of SONGS was $540 million as of December 31, 2022, based on the decommissioning cost study prepared in 2020. Changes in the estimated costs, execution strategy or timing of decommissioning, or in the assumptions and judgments by management underlying these estimates, could cause material revisions to the estimated total cost to decommission this facility, which could have a material effect on the recorded liability.
The following table illustrates the increase to SDG&E’s and Sempra’s ARO liability if the cost escalation rate was adjusted while leaving all other assumptions constant:
Uniform increase in escalation percentage of 1 percentage point
$
62
The increase in the ARO liability driven by an increase in the cost escalation rate would result in a decrease in the regulatory liability for recoveries in excess of ARO liabilities. We provide additional detail in Note 15 of the Notes to Consolidated Financial Statements.
Whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the asset. If so, we estimate the fair value of the asset to determine the extent to which carrying value exceeds fair value. For such an estimate, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful life of a long-lived asset and to determine our intent to use the asset. Our intent to use or dispose of a long-lived asset is
subject to re-evaluation and can change over time. If an impairment test is required, the fair value of a long-lived asset can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. Critical assumptions that affect our estimates of fair value may include:
▪consideration of market transactions
▪future cash flows
▪the appropriate risk-adjusted discount rate, including the impacts of country risk and entity risk
We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements.
IMPAIRMENT TESTING OF GOODWILL
Sempra
When determining if goodwill is impaired, the fair value of the reporting unit can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a goodwill impairment may or may not be required. When we perform the quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and compare that to its carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as a discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical
assumptions that affect our estimates of fair value may include:
▪consideration of market transactions
▪future cash flows
▪projected revenue and expense growth rates
▪the appropriate risk-adjusted discount rate, including the impacts of country risk and entity risk
In 2022 and 2021, we performed a quantitative goodwill impairment test and determined that the estimated fair values of our reporting units in Mexico to which goodwill was allocated was substantially above their carrying value for each year as of October 1, our goodwill impairment testing date. Our goodwill impairment test is determined based on assumptions existing as
of that point in time. Changes in the business (such as loss of future cash flows from customer disputes, renegotiation of customer contracts or the macroeconomic environment, including rising interest rates) may result in us having to perform an interim goodwill impairment test, which could result in an impairment of our goodwill.
NEW ACCOUNTING STANDARDS
We discuss the recent accounting pronouncements that have had or may have a significant effect on our financial statements and/or disclosures in Note 2 of the Notes to Consolidated Financial Statements.
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.
Sempra has policies governing its market risk management and trading activities. Sempra,
SDG&E, SoCalGas and Sempra Infrastructure maintain separate risk management committees, organizations and processes to provide oversight of these activities for their respective businesses. The committees consist of senior officers who establish policy, oversee energy risk management activities, and monitor the results of trading and other activities to help ensure compliance with our stated energy risk management and trading policies. These activities include, but are not limited to, monitoring of market positions that create credit, liquidity and market risk. The respective oversight organizations and committees are independent from energy procurement departments.
Along with other tools, we use VaR and liquidity metrics to measure our exposure to market risk associated with commodity portfolios. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal
market conditions and within a given statistical confidence interval. We use a variance-covariance VaR model at a 95% confidence level. A liquidity metric is intended to monitor the amount of financial resources needed for meeting potential margin calls as forward market prices move. VaR and liquidity risk metrics are independently verified by the respective risk management oversight organizations.
SDG&E and SoCalGas use natural gas derivatives and SDG&E uses electricity derivatives to manage natural gas and electric price risk associated with servicing load requirements. The use of natural gas and electricity derivatives is subject to certain limitations imposed by company policy and regulatory requirements. SDG&E’s risk management and transacting activity plans for electricity derivatives are also required to be filed with, and have been approved by, the CPUC. SoCalGas is also subject to certain regulatory requirements
and thresholds related to natural gas procurement under the GCIM. We discuss revenue recognition in Note 3 and additional market-risk information regarding derivative instruments in Note 11 of the Notes to Consolidated Financial Statements.
We have exposure to changes in commodity prices, interest rates and foreign currency and inflation rates. The following discussion of these primary market-risk exposures as of December 31, 2022 includes a discussion of how these exposures are managed.
COMMODITY PRICE RISK
Market risk related to physical commodities is created by volatility in the prices and basis of certain commodities. Our various subsidiaries are exposed, in varying degrees, to commodity price risk, primarily to prices in the natural gas and electricity markets. Our policy is to manage
this risk within a framework that considers the specific markets and operating and regulatory environments of each subsidiary.
Sempra Infrastructure is exposed to commodity price risk indirectly through its LNG, natural gas pipelines and storage, and power-generating assets. Sempra Infrastructure has utilized and may continue to utilize commodity contracts, including physical and financial derivatives, in an effort to mitigate these risks and optimize the value of these assets. These transactions are typically priced based on market indices, but may also include fixed price purchases and sales of commodities. Any residual exposure is monitored as described above. Some of these derivatives that we use as economic hedges do not meet the requirements for hedge accounting, or hedge accounting is not elected, and as a result, the changes in fair value of these derivatives are recorded in earnings. Consequently, significant changes
in commodity prices have in the past and could in the future result in earnings volatility as the economic offset of these derivatives may not be recorded at fair value. A significant decrease in the fair value of these economic hedges could also result in higher collateral requirements, which could negatively impact our liquidity and our ability to continue to mitigate our commodity risk exposure. We try to structure our hedging transactions with the objective that over time (i) realized gains and losses on our economic hedges would be largely offset by gains and losses related to our purchases or sales of natural gas and (ii) we would realize the economic benefit we anticipated at the time we structured the original transaction.
A hypothetical 10% change in commodity prices would have resulted in a change in the fair value of our commodity-based natural gas and electricity derivatives of $24 million and $3 million at December 31,
2022 and 2021, respectively. The impact of a change in energy commodity prices on our commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled and does not typically include the generally offsetting impact of our underlying asset positions.
SDG&E and SoCalGas separately manage risk within the parameters of their market risk management frameworks. In addition, their market-risk exposure is limited due to CPUC-authorized rate recovery of the costs of commodity purchases, interstate and intrastate transportation, and storage activity. However, SoCalGas may, at times, be exposed to market risk as a result of the
GCIM, which rewards or penalizes the utility for commodity costs below or above certain benchmarks. The one-day VaR for SDG&E and SoCalGas’ commodity positions were $25 million and $2 million, respectively, at December 31, 2022 and $5 million and $1 million, respectively, at December 31, 2021.
INTEREST RATE RISK
We are exposed to fluctuations in interest rates primarily from our short- and long-term debt. Subject to regulatory constraints, we periodically enter into interest rate swap agreements to moderate our exposure to interest rate changes and to lower our overall cost of borrowing.
The
table below shows the nominal amount of our debt:
(1) After
the effects of interest rate swaps. Before reductions for unamortized discount and debt issuance costs and excluding finance lease obligations at December 31, 2022 and 2021, and before the effects of acquisition-related fair value adjustments at December 31, 2021.
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, 2022 increased or decreased by 10%, the change in earnings
over the 12-month period ending December 31, 2023 would be approximately $12 million. If interest rates increased or decreased by 10% on all variable-rate long-term debt at December 31, 2022, after considering the effects of interest rate swaps, the change in earnings over the 12-month period ending December 31, 2023 would be approximately $5 million.
We provide further information about debt and interest rate swap transactions in Notes 7 and 11, respectively, of the Notes to Consolidated Financial Statements.
We also are subject to the effect of interest rate fluctuations on the assets of our pension plans, PBOP plans, and SDG&E’s NDT. However, we expect the effects of these fluctuations, as they relate to Sempra California, to
be reflected in future rates.
FOREIGN CURRENCY EXCHANGE RATE RISK AND INFLATION EXPOSURES
We discuss our foreign currency exchange rate risk 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 2022 earnings to U.S. dollars(2)
$
(3)
Transactional exposure(3)
153
Translation
of net assets of foreign subsidiaries and investment in foreign entities(4)
(19)
(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, 2022 on monetary assets and liabilities and remeasurement of non-U.S. deferred income tax balances at our Mexican subsidiaries.
(4) Amount represents the effects of currency
exchange rate movement from December 31, 2022 that would be recorded to OCI at the end of the reporting period.
Monetary assets and liabilities at our Mexican subsidiaries and JVs that are denominated in U.S. dollars may fluctuate significantly throughout the year. These monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. Based on a net monetary liability position of $4.8 billion, including those related to our investments in JVs, at December 31, 2022, the hypothetical effect of a 10% increase in the Mexican inflation rate is approximately $104 million lower earnings as a result of higher income tax expense for our consolidated entities, as well as lower equity earnings for our JVs.
In
2022 and 2023 to date, SDG&E and SoCalGas have experienced inflationary pressures from increases in various costs, including the cost of natural gas, electric fuel and purchased power, labor, materials and supplies, as well as availability of labor and materials. Sempra Texas Utilities has experienced increased costs of labor and materials and does not have specific regulatory mechanisms that allow for recovery of higher costs due to inflation; rather, recovery is limited to rate updates through capital trackers and base rate reviews, which may result in partial non-recovery due to the regulatory lag. If such costs were to continue to be subject to significant inflationary pressures and we are not able to fully recover such higher costs in rates or there is a delay in recovery, these increased costs may have a significant effect on Sempra’s, SDG&E’s and SoCalGas’ results of operations, financial condition, cash flows and/or prospects.
Sempra
Infrastructure has experienced inflationary pressures from increases in various costs, including the cost of labor, materials and supplies. Sempra Infrastructure generally secures long-term contracts that are U.S. dollar-denominated or referenced and are periodically adjusted for market factors, including inflation, and Sempra Infrastructure generally enters into lump-sum contracts for its large construction projects in which much of the risk during construction is absorbed or hedged by the EPC contractor. If additional costs were to become subject to significant inflationary pressures, we may not be able to fully recover such higher costs through contractual adjustments for inflation, which may have a significant effect on Sempra’s results of operations, financial condition, cash flows and/or prospects.
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
Sempra, SDG&E and SoCalGas maintain disclosure controls and procedures designed to ensure that information required to be disclosed in their respective reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and is accumulated and communicated to the management of each company, including each respective principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures,
the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2022, the end of the period covered by this report. Based on these evaluations, the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas concluded that their respective company’s disclosure controls
and procedures were effective at the reasonable assurance level as of such date.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Sempra, SDG&E, SoCalGas
The respective management of Sempra, SDG&E and SoCalGas is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f).
Under the supervision and with the participation of the principal executive officers and principal financial officers of Sempra, SDG&E and SoCalGas, each such company’s management evaluated the effectiveness of its internal control over financial reporting based on the framework in Internal
Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on these evaluations, each company’s management concluded that its internal control over financial reporting was effective as of December 31, 2022. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2022, as stated in their reports, which are included in this annual report on Form 10-K.
There have been no changes in Sempra’s, SDG&E’s or SoCalGas’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are
reasonably likely to materially affect, any such company’s internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Shareholders and Board of Directors of Sempra Energy:
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Sempra Energy and subsidiaries (“Sempra”) as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, Sempra maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, 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, 2022, of Sempra and our report dated February 28, 2023, expressed an unqualified opinion on those financial statements.
Basis for Opinion
Sempra’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Sempra’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sempra in accordance
with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A
company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition,
use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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, 2022, 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, 2022, 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, 2022, of SDG&E and our report dated February 28, 2023, 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, 2022, 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, 2022, 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, 2022, of SoCalGas and our report
dated February 28, 2023, 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.
ITEM
9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III.
Because SDG&E meets the conditions of General Instructions I(1)(a)
and (b) of Form 10-K and is therefore filing this report with a reduced disclosure format as permitted by General Instruction I(2), the information required by Part III – Items 10, 11, 12 and 13 below is not required for SDG&E. We have, however, voluntarily provided the information required by Item 401 of SEC Regulation S-K, as required by Part III – Item 10 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 Item 401 of SEC Regulation S-K, as required by this item, with respect to executive officers of Sempra and SoCalGas in “Part I – Item 1. Business – Other Matters – Information About Our Executive Officers.” All other information required by this item is incorporated by reference from “Corporate Governance” and “Proposal 1: Election of Directors” in the proxy statement to be filed for the May 2023 annual meeting of shareholders for Sempra and from the information statement to be filed for the May 2023 annual meeting of shareholders for SoCalGas. In all cases, only the specific information that is expressly required by this item is incorporated herein by reference.
ITEM
11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from “Executive Compensation,” including “Compensation Discussion and Analysis,”“Compensation and Talent Committee Report” and “Compensation Tables” (except for the disclosure under the heading “Pay-Versus-Performance”), in the proxy statement to be filed for the May 2023 annual meeting of shareholders for Sempra and from the information statement to be filed for the May 2023 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 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, 2022, outstanding awards consisted of stock options and RSUs held by 424 employees.
The
following table sets forth information regarding our equity compensation plans at December 31, 2022.
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
151,876
$
106.76
—
2019
LTIP
1,680,168
$
132.47
5,056,550
(1)The 2013 LTIP consists of 151,876 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, no performance-based RSUs and no service-based RSUs. The 2019 LTIP consists of 564,736 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, 839,795 performance-based RSUs
and 275,637 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 151,876 and 564,736 outstanding options to purchase shares of our common stock under the 2013 LTIP and the 2019 LTIP, respectively.
(3)The number of shares available for future issuance is increased by the number of shares to which each participant would otherwise be entitled that are withheld or
surrendered to satisfy the exercise price or to satisfy tax withholding obligations relating to any plan awards, and is also increased by the number of shares subject to awards that expire or are forfeited, canceled or otherwise terminated without the issuance of shares. No new awards may be granted under the 2013 LTIP.
We provide additional discussion of share-based compensation in Note 10 of the Notes to Consolidated Financial Statements.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information required by Item 403 of SEC Regulation S-K, as required by this item, is incorporated by reference from “Share Ownership” in the proxy statement to be filed for the May 2023 annual meeting of shareholders for Sempra and from the information statement
to be filed for the May 2023 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 this item is incorporated by reference from “Corporate Governance” in the proxy statement to be filed for the May 2023 annual meeting of shareholders for Sempra and from the information statement to be filed for the May 2023 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.
Information regarding principal accountant fees and services is presented below for Sempra, SDG&E and SoCalGas. The following table shows the fees paid to Deloitte
& Touche LLP, the independent registered public accounting firm for Sempra, SDG&E and SoCalGas, for services provided for 2022 and 2021.
PRINCIPAL
ACCOUNTANT FEES
(Dollars in thousands)
Sempra
SDG&E
SoCalGas
Fees
Percent of total
Fees
Percent of total
Fees
Percent
of total
2022:
Audit fees:
Consolidated
financial statements, internal controls audits and subsidiary audits
$
10,872
$
3,013
$
3,549
Regulatory filings and related services
290
65
130
Total
audit fees
11,162
83
%
3,078
87
%
3,679
92
%
Audit-related fees:
Employee
benefit plan audits
520
169
287
Other audit-related services(1)
1,245
165
—
Total
audit-related fees
1,765
13
334
10
287
7
Tax fees(2)
477
3
116
3
17
1
All
other fees(3)
94
1
—
—
—
—
Total fees
$
13,498
100
%
$
3,528
100
%
$
3,983
100
%
2021:
Audit
fees:
Consolidated financial statements, internal controls audits and subsidiary audits
$
10,166
$
2,753
$
3,486
Regulatory
filings and related services
807
60
—
Total audit fees
10,973
81
%
2,813
87
%
3,486
91
%
Audit-related
fees:
Employee benefit plan audits
520
184
309
Other
audit-related services(1)
1,840
119
—
Total audit-related fees
2,360
17
303
9
309
8
Tax
fees(2)
272
2
113
4
33
1
All other fees(3)
13
—
—
—
8
—
Total
fees
$
13,618
100
%
$
3,229
100
%
$
3,836
100
%
(1)Other
audit-related services primarily relate to statutory audits and agreed upon procedures.
(2)Tax fees relate to tax consulting and compliance services.
(3)All other fees relate to training and conferences.
The Audit Committee of Sempra’s board of directors is directly responsible for the appointment, compensation, retention and oversight, including the oversight of the audit fee negotiations, of the independent registered public accounting firm for Sempra and its subsidiaries, including SDG&E and SoCalGas. As a matter of good corporate governance, each of the Sempra, SDG&E and SoCalGas boards of directors reviewed the performance of Deloitte &
Touche LLP and appointed them as the independent registered public accounting firm for each of Sempra, SDG&E and SoCalGas, respectively. Sempra’s board of directors has determined that each member of its Audit Committee is an independent director and is financially literate, and that Mr. Jack T. Taylor, who chairs the committee, and Ms. Cynthia L. Walker, who is a member of the committee, are audit committee financial experts as defined by the rules of the SEC.
Except where pre-approval is not required by SEC rules, Sempra’s Audit Committee pre-approves all audit, audit-related and permissible non-audit services provided by Deloitte & Touche LLP for Sempra and its
subsidiaries, including all services provided by Deloitte & Touche LLP for Sempra, SDG&E and SoCalGas in 2022 and 2021. The committee’s pre-approval policies and procedures provide for the general pre-approval of specific types of services and give detailed guidance to management as to the services that are eligible for general pre-approval, and they require specific pre-approval of all other permitted services. For both types of pre-approval, the committee considers whether the services to be provided are consistent
with
maintaining the firm’s independence. The committee’s policies and procedures also delegate authority to the Chair of the committee to address any requests for pre-approval of services between committee meetings, with any pre-approval decisions to be reported to the committee at its next scheduled meeting.
PART
IV.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
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.
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 SEC 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.
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.
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.
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of Sempra Energy, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this
report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws.
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.
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.
Each of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of San Diego Gas & Electric Company, and each of them singly (with full power to each of them
to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable
federal securities laws. 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.
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 to security holders covering the registrant’s last fiscal year and no proxy statement, form of proxy or other proxy soliciting material with respect to any annual or other meeting of security holders 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.
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.
Each
of the undersigned officers and directors of the registrant hereby severally constitutes and appoints each individual who, at the time of acting under this power of attorney, is the Principal Executive Officer (however designated), the Principal Financial Officer (however designated) or the Principal Accounting Officer (however designated) of Southern California Gas Company, and each of them singly (with full power to each of them to act alone), as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution in each of them, for him or her and in his or her name, place and stead, and in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the U.S. Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act
and thing requisite and necessary to be done in connection therewith as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof. This power of attorney shall be governed by and construed in accordance with the laws of the State of California and applicable federal securities laws. 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”) as of December 31, 2022 and 2021, 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, 2022, the related notes, and the schedule listed in Item 15 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of Sempra as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with
accounting principles generally accepted in the United States of America (“U.S. GAAP”).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), Sempra’s internal control over financial reporting as of December 31, 2022, 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 28, 2023, expressed an unqualified opinion on Sempra’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of Sempra’s
management. Our responsibility is to express an opinion on Sempra’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sempra in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit 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
Sempra is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such
as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets
or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We read relevant regulatory orders issued by the Commissions for Sempra and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
▪We evaluated Sempra’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
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 balance sheets of San Diego Gas & Electric Company (“SDG&E”) as of December 31,
2022 and 2021, the related statements of operations, comprehensive income (loss), changes in shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 28, 2023, expressed an unqualified opinion on SDG&E’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of SDG&E’s management. Our responsibility is to express an opinion on SDG&E’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB
and are required to be independent with respect to SDG&E in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating
the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting
– Impact of Rate Regulation on the Financial Statements – Refer to Note 1 of the Notes to Consolidated Financial Statements
Critical Audit Matter Description
SDG&E is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of electric and gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation
expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets
or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We read relevant regulatory orders issued by the Commissions for SDG&E and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.
▪We evaluated SDG&E’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
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, 2022 and 2021, 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, 2022, 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,
2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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 28, 2023, 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 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 Financial Statements
Critical Audit Matter Description
SoCalGas is subject to rate regulation by regulators and commissions in various jurisdictions (collectively, the “Commissions”) that have jurisdiction with respect to the rates of gas transmission and distribution companies in those jurisdictions. Management has determined it meets the requirements under U.S. GAAP to
prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; operation and maintenance expense; depreciation expense; and taxes.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management’s judgments include assessing the likelihood of (1) the recovery in future rates of incurred costs and (2) potential refunds to customers. Auditing these judgments required specialized knowledge of accounting
for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the application of specialized rules to account for the effects of cost-based rate regulation and the uncertainty of future decisions by the Commissions included the following, among others:
▪We tested the
effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
▪We read relevant regulatory orders issued by the Commissions for SoCalGas and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s
recorded regulatory asset and liability balances for completeness.
▪We evaluated SoCalGas’ disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
NOTE
1. iSIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA
i
PRINCIPLES
OF CONSOLIDATION
Sempra
Sempra’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based holding company doing business as Sempra, and its consolidated entities. We have ifour separate reportable segments, which we discuss in Note 17. All references in these Notes to our reportable segments are not intended to refer to any legal entity with the same or similar name.
SDG&E
SDG&E’s
common stock is wholly owned by Enova, which is a wholly owned subsidiary of Sempra.
SoCalGas
SoCalGas’ common stock is wholly owned by PE, which is a wholly owned subsidiary of Sempra.
/
iBASIS OF PRESENTATION
This is a combined report of Sempra, SDG&E and
SoCalGas. We provide separate information for SDG&E and SoCalGas as required. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.
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
We completed the sales of our equity interests in our Peruvian businesses in April 2020 and our Chilean businesses in June 2020. We determined that these businesses, which previously constituted the Sempra South American Utilities segment, and certain activities associated with these businesses, met the held-for-sale criteria upon our decision to sell them in January 2019. These
businesses are presented as discontinued operations, which we discuss further in Note 5. Our discussions in the Notes below relate only to our continuing operations unless otherwise noted.
i
Subsequent Events
We evaluated events and transactions that occurred after December 31, 2022 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
REGULATED
OPERATIONS
SDG&E’s and SoCalGas’ accounting policies and financial statements reflect the application of U.S. GAAP provisions governing rate-regulated operations and the policies of the CPUC and the FERC. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains
on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, SDG&E and SoCalGas record regulatory liabilities when the CPUC or, in
the case of SDG&E, the FERC, requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.
Determining probability of
recovery of regulatory assets requires judgment by management and may include, but is not limited to, consideration of:
▪the nature of the event giving rise to the assessment
▪existing statutes and regulatory code
▪legal precedents
▪regulatory principles and analogous regulatory actions
▪testimony presented in regulatory hearings
▪regulatory orders
▪a commission-authorized mechanism established for the accumulation of costs
▪status
of applications for rehearings or state court appeals
▪specific approval from a commission
▪historical experience
Sempra Infrastructure’s natural gas distribution utility, Ecogas, also applies U.S. GAAP provisions for rate-regulated operations, including the same evaluation of probability of recovery of regulatory assets described above.
Our Sempra Texas Utilities segment is comprised of our equity method investments in Oncor Holdings, which owns an 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, in the case of Oncor, certain cities and are subject to regulatory rate-setting processes and earnings oversight. Oncor and Sharyland Utilities prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations.
Our Sempra Infrastructure segment includes
the operating companies of our subsidiary, IEnova, as well as certain holding companies and risk management activity. Certain business activities at IEnova are regulated by the CRE and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction at IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of AFUDC related to equity. We discuss AFUDC below in “Property, Plant and Equipment.”
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.
We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical
assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 – Pricing inputs are unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, short-term investments, and U.S. government treasury securities, primarily in the NDT and benefit plan trusts, and exchange-traded derivatives.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable
as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:
▪quoted forward prices for commodities
▪time value
▪current market and contractual prices for the underlying instruments
Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include listed equities, domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the NDT and benefit plan trusts, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter forwards and options.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best
estimate of fair value from the perspective of a market participant. Our Level 3 financial instruments consist of CRRs and fixed-price electricity positions at SDG&E and the Support Agreement at Sempra Infrastructure.
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:
▪for Sempra Infrastructure, funds fully drawn against Gazprom’s letters of credit, including draws associated with its LNG storage and regasification agreement that we discuss in Note 16, and funds denominated in Mexican pesos to pay for rights-of-way, license fees, permits, topographic surveys and other costs pursuant to trust and debt agreements related to pipeline projects
▪for Parent and other, funds held in a delisting trust for the purpose of purchasing the remaining publicly owned IEnova shares
i
The
following table provides a reconciliation of cash, cash equivalents and restricted cash reported on Sempra’s Consolidated Balance Sheets to the sum of such amounts reported on Sempra’s Consolidated Statements of Cash Flows.
RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Total
cash, cash equivalents and restricted cash on the Consolidated Statements of Cash Flows
$
i462
$
i581
/
i
CREDIT
LOSSES
We are exposed to credit losses from financial assets measured at amortized cost, including trade and other accounts receivable, amounts due from unconsolidated affiliates, our net investment in a sales-type lease and a note receivable. We are also exposed to credit losses from off-balance sheet arrangements through Sempra’s guarantee related to Cameron LNG JV’s SDSRA, which we discuss in Note 6.
We regularly monitor and evaluate credit losses and record allowances for expected credit losses, if necessary, for trade and other accounts receivable using a combination of factors, including past-due status based on contractual terms, trends in write-offs, the age of the receivables and customer payment patterns, historical and industry trends, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies, pandemics and other factors. We write off
financial assets measured at amortized cost in the period in which we determine they are not recoverable. We record recoveries of amounts previously written off when it is known that they will be recovered.
In 2021, SDG&E and SoCalGas applied, on behalf of their customers, for financial assistance from the California Department of Community Services and Development under the 2021 California Arrearage Payment Program, which provided funds of $i63 million and $i79 million
for SDG&E and SoCalGas, respectively. In the first quarter of 2022, SDG&E and SoCalGas received and applied the amounts directly to eligible customer accounts to reduce past due balances. In June 2022, AB 205 was approved establishing, among other things, the 2022 California Arrearage Payment Program. In December 2022, SDG&E and SoCalGas received funding of $i51 million and $i59 million,
respectively, related to this program and, in January 2023, applied the amounts directly to eligible customer accounts to reduce past due balances.
We
provide below the changes in allowances for credit losses for trade receivables and other receivables. SDG&E and SoCalGas record changes in the allowances for credit losses related to Accounts Receivable – Trade in regulatory accounts.
CHANGES IN ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
2022
2021
2020
Sempra:
Allowances
for credit losses at January 1
$
i136
$
i138
$
i29
Incremental
allowance upon adoption of ASU 2016-13
i—
i—
i1
Provisions
for expected credit losses
i123
i45
i124
Write-offs
(i78)
(i47)
(i16)
Allowances
for credit losses at December 31
$
i181
$
i136
$
i138
SDG&E:
Allowances
for credit losses at January 1
$
i66
$
i69
$
i14
Provisions
for expected credit losses
i54
i23
i65
Write-offs
(i42)
(i26)
(i10)
Allowances
for credit losses at December 31
$
i78
$
i66
$
i69
SoCalGas:
Allowances
for credit losses at January 1
$
i69
$
i68
$
i15
Provisions
for expected credit losses
i65
i22
i59
Write-offs
(i36)
(i21)
(i6)
Allowances
for credit losses at December 31
$
i98
$
i69
$
i68
Allowances
for credit losses related to trade receivables and other receivables are included in the Consolidated Balance Sheets as follows:
As
we discuss below in “Transactions with Affiliates,” we had a loan due from an unconsolidated affiliate that was paid in full in July 2022. At December 31, 2021, $i1 million of expected credit losses are included in noncurrent Due From Unconsolidated Affiliates on Sempra’s Consolidated Balance Sheet.
As we discuss below in “Note Receivable,” we have an interest-bearing promissory note due from KKR. On a quarterly basis, we evaluate
credit losses and record allowances for expected credit losses on this note receivable, including compounded interest and unamortized transaction costs, based on published default rate studies, the maturity date of the instrument and an internally developed credit rating. At December 31, 2022 and 2021, $i7 million and $i8 million,
respectively, of expected credit losses is included in Other Long-Term Assets on Sempra’s Consolidated Balance Sheets.
As we discuss below in Note 6, Sempra provided a guarantee for the benefit of Cameron LNG JV related to amounts withdrawn by Sempra Infrastructure from the SDSRA. On a quarterly basis, we evaluate credit losses and record liabilities for expected credit losses on this off-balance sheet arrangement based on external credit ratings, published default rate studies and the maturity
date
of the arrangement. At December 31, 2022 and 2021, $i6 million and $i7 million,
respectively, of expected credit losses are included in Deferred Credits and Other on Sempra’s Consolidated Balance Sheets.
i
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.
i
INVENTORIES
SDG&E
and SoCalGas value natural gas inventory using the last-in first-out method. As inventories are sold, differences between the last-in first-out valuation and the estimated replacement cost are reflected in customer rates. These differences are generally temporary, but may become permanent if the natural gas inventory withdrawn from storage during the year is not replaced by year end. SDG&E and SoCalGas generally value materials and supplies at the lower of average cost or net realizable value.
Sempra Infrastructure values natural gas inventory and materials and supplies at the lower of average cost or net realizable value, and LNG inventory using the first-in first-out method.
i
The
components of inventories are as follows:
INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
Sempra
SDG&E
SoCalGas
2022
2021
2022
2021
2022
2021
Natural
gas
$
i106
$
i164
$
i1
$
i—
$
i74
$
i114
LNG
i62
i27
i—
i—
i—
i—
Materials
and supplies
i235
i198
i133
i123
i85
i58
Total
$
i403
$
i389
$
i134
$
i123
$
i159
$
i172
/
NOTE
RECEIVABLE
In November 2021, Sempra loaned $i300 million to KKR in exchange for an interest-bearing promissory note that is due in full no later than October 2029 and bears compound interest at i5%
per annum, which may be paid quarterly or added to the outstanding principal at the election of KKR. At December 31, 2022 and 2021, Other Long-Term Assets includes $i316 million and $i297
million, respectively, of outstanding principal, compounded interest and unamortized transaction costs, net of allowance for credit losses, and at December 31, 2021, Other Current Assets includes $i3 million of interest receivable on Sempra’s Consolidated Balance Sheets.
In July 2019, the Wildfire Legislation was signed into law to address certain issues related to catastrophic wildfires in 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 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 $i1.0
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 OEIS 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 2022 rate base, the liability cap for SDG&E is approximately $i1.2 billion, which is adjusted annually. The liability cap will apply on a rolling three-year basis so long as future annual safety certifications are received and the Wildfire Fund has not been terminated, which could occur if funds are exhausted. Amounts in excess of the liability cap and amounts that are determined to be prudently incurred do not
need to be reimbursed by an IOU to the Wildfire Fund. The Wildfire Fund does not have a specified term and coverage will continue until the assets of the Wildfire Fund are exhausted and the Wildfire Fund is terminated, in which case, the remaining funds, if any, will be transferred to California’s general fund to be used for fire risk mitigation programs.
In August 2022, the OEIS approved SDG&E’s 2022 Wildfire Mitigation Plan, which is effective until the OEIS approves a new plan. SDG&E received its annual wildfire safety certification from the OEIS in December 2022.
The Wildfire Fund was initially funded up to $i10.5
billion by a loan from the California Surplus Money Investment Fund. The loan is financed through a DWR bond, which was put in place in October 2020 and is securitized through a dedicated surcharge on ratepayers’ bills attributable to the DWR. In October 2019, the CPUC adopted a decision authorizing a non-bypassable charge to be collected by the IOUs to support the anticipated DWR bond issuance authorized by AB 1054. The CPUC decision also determined that ratepayers of non-participating electrical corporations shall not pay the non-bypassable charge.
The Wildfire Fund was also funded by initial shareholder contributions from the IOUs totaling $i7.5
billion. SDG&E’s share was $i322.5 million. 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. The contributions are not subject to rate recovery.
Wildfire
Fund Asset and Obligation
In 2019, SDG&E recorded both a Wildfire Fund asset and a related obligation for its commitment to make shareholder contributions of $i451.5 million to the Wildfire Fund, measured at present value as of July 25, 2019 (the date by which both Edison and SDG&E opted to contribute to the Wildfire Fund). SDG&E paid its initial shareholder contribution of $i322.5
million to the Wildfire Fund in September 2019. SDG&E funded this contribution with proceeds from an equity contribution from
Sempra. SDG&E expects to continue to make annual shareholder contributions of $i12.9 million
through December 31, 2028. SDG&E is accreting 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 California, including frequency and severity of the wildfires
▪the value of property potentially damaged by wildfires
▪the effectiveness of wildfire risk mitigation efforts by each IOU
▪liability cap of each IOU
▪IOU prudency determination levels
▪FERC jurisdictional allocation levels
▪insurance coverage levels
The use of different assumptions, or changes to the assumptions used, could have a significant impact on the estimated period of benefit of the Wildfire Fund
asset. SDG&E periodically evaluates the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in these assumptions. SDG&E recognizes a reduction of its Wildfire Fund asset and records a charge against earnings in the period when there is a reduction of the available coverage due to recoverable claims from any of the participating IOUs. Wildfire claims that are recoverable from the Wildfire Fund, net of anticipated or actual reimbursement to the Wildfire Fund by the responsible IOU, decrease the Wildfire Fund asset and remaining available coverage.
i
The
following table summarizes the location of balances related to the Wildfire Fund on Sempra’s and SDG&E’s Consolidated Balance Sheets and Consolidated Statements of Operations.
Income tax expense includes current and deferred income taxes. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. Investment tax credits from prior years are amortized to income by SDG&E and SoCalGas over the estimated service lives of the properties as required by the CPUC.
Under the regulatory accounting treatment required for flow-through temporary differences, SDG&E, SoCalGas and Sempra Infrastructure recognize:
▪regulatory assets to offset deferred income tax liabilities if it is probable that the amounts will be recovered from customers; and
▪regulatory liabilities to offset deferred income tax assets if it is probable that the amounts will be returned
to customers.
When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a more-likely-than-not chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more-likely-than-not” means a likelihood of more than 50%. Otherwise, we may not recognize
any of the potential tax benefit associated
with the position. We recognize a benefit for a tax position that meets the more-likely-than-not criterion at the largest amount of tax benefit that is greater than 50% likely of being realized upon its effective resolution.
Unrecognized income tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our ETR.
We accrue income tax to the extent we intend to repatriate cash to the U.S. from our continuing international operations. We currently do not record deferred income taxes for other basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries because they are indefinitely reinvested. We recognize income tax expense for basis differences related to global intangible low-taxed income
as a period cost if and when incurred.
We provide additional information about income taxes in Note 8.
i
GREENHOUSE GAS ALLOWANCES AND OBLIGATIONS
SDG&E, SoCalGas and Sempra Infrastructure are required by AB 32 to acquire GHG allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric
generation and natural gas consumption. At SDG&E and SoCalGas, many GHG allowances are allocated to us on behalf of our customers at no cost and we purchase any additional allowances required. We record purchased and allocated GHG allowances at the lower of weighted-average cost or market. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts. Sempra Infrastructure records the cost of GHG obligations in cost of sales. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.
RENEWABLE
ENERGY CERTIFICATES
RECs are energy rights established by governmental agencies for the environmental and social promotion of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.
Retail sellers of electricity obtain RECs through renewable energy PPAs, internal generation or separate purchases in the market to comply with the RPS Program established by the governmental agencies. RECs provide documentation for the generation of a unit of renewable energy that is used to verify compliance with the RPS Program. The cost of RECs at SDG&E, which is recoverable in rates, is recorded in Cost of Electric Fuel and Purchased Power on the Statements of Operations.
iPROPERTY,
PLANT AND EQUIPMENT
PP&E is recorded at cost and primarily represents the buildings, equipment and other facilities used by SDG&E and SoCalGas to provide natural gas and electric utility services, and by the Sempra Infrastructure businesses in their operations, including construction work in progress. PP&E also includes lease improvements and other equipment at Parent and other. Our plant costs include labor, materials and contract services and expenditures for replacement parts incurred during a major maintenance outage of a plant. In addition, the cost of utility plant at our rate-regulated businesses and PP&E under regulated projects that meet the regulatory accounting requirements of U.S. GAAP includes AFUDC. The cost of PP&E for our non-regulated projects includes capitalized interest. Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant assets less salvage
value is charged to accumulated depreciation. We discuss assets collateralized as security for certain indebtedness in Note 7.
(1) At
December 31, 2022, includes $i554 in electric transmission assets and $i7 in construction work in progress related to SDG&E’s i86%
interest in the Southwest Powerlink transmission line, jointly owned by SDG&E with other utilities. SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for its share of the project and participates in decisions concerning operations and capital expenditures. SDG&E’s share of operating expenses is included in Sempra’s and SDG&E’s Consolidated Statements of Operations.
(2) Includes $i246 and $i211
at December 31, 2022 and 2021, respectively, of utility plant, primarily pipelines and other distribution assets at Ecogas.
(3)Estimated useful lives are for land rights.
/
Depreciation expense is computed using the straight-line method over the asset’s estimated composite useful life, the CPUC-prescribed period for SDG&E and SoCalGas, or the remaining term of the site leases, whichever is shortest.
Electric
transmission, distribution and generation(1)
i5,789
i5,489
Total
SDG&E
i6,768
i6,408
SoCalGas:
Accumulated
depreciation:
Natural gas operations
i7,291
i6,845
Other
non-utility
i17
i16
Total
SoCalGas
i7,308
i6,861
Sempra
Infrastructure and parent:
Accumulated depreciation – other(2)
i2,035
i1,777
Total
Sempra
$
i16,111
$
i15,046
(1) Includes
$i307 at December 31, 2022 related to SDG&E’s i86% interest in the Southwest
Powerlink transmission line, jointly owned by SDG&E and other utilities.
(2) Includes $i65 and $i55
at December 31, 2022 and 2021, respectively, of accumulated depreciation for utility plant at Ecogas.
i
SDG&E and SoCalGas finance construction projects with debt and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization
of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of PP&E. SDG&E and SoCalGas earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.
Pipeline projects under construction by Sempra Infrastructure that are both subject to certain regulation and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC.
We capitalize interest costs incurred to finance capital projects and interest at equity method investments that have not commenced planned principal operations.
i
The
table below summarizes capitalized financing costs, comprised of AFUDC and capitalized interest.
Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized, but we test it for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, we record a goodwill impairment loss as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill.
For
our annual goodwill impairment testing, we have the option to first make a qualitative assessment of whether it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, then we perform the quantitative goodwill impairment test. If, after performing the quantitative goodwill impairment test, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not
to exceed the carrying amount of goodwill.
Goodwill of $ii1,602/ million at December
31, 2022 and 2021 relates to the 2016 acquisitions of IEnova Pipelines and the Ventika wind power generation facilities at Sempra Infrastructure.
Other Intangible Assets
i
Other Intangible Assets included on Sempra’s Consolidated Balance Sheets are as follows:
▪renewable energy transmission and consumption permits previously granted by the CRE at the Ventika wind power generation facilities, Don Diego Solar and Border Solar;
▪a favorable O&M agreement acquired in connection with the acquisition of DEN; and
▪the relative fair value of the PPA that was acquired in connection with the acquisition of ESJ.
Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for intangible assets was $i26
million (including $i13 million recorded against revenues) in 2022, $i22 million (including $i10
million recorded against revenues) in 2021, and $i11 million in 2020. We estimate amortization expense for the next five years to be $iiiii26////
million per year (including $i13 million per year recorded against revenues).
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.
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 nature of the VIE’s risks and the risks we absorb;
▪the
power to direct activities that most significantly impact the economic performance of the VIE; and
▪the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.
We will continue to evaluate our VIEs for any changes that may impact our determination of whether an entity is a VIE and if we are the primary beneficiary.
SDG&E
SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs that include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and indirectly Sempra, is the primary beneficiary.
SDG&E
has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based on our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity
owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which it considers the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If SDG&E determines that it is the primary beneficiary, SDG&E and Sempra consolidate the entity that owns the facility as a VIE.
In addition to tolling agreements, other variable interests involve various elements of fuel and power costs, and other components of cash flows expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities, including the operation and maintenance activities of the generating facility, that most significantly
impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects could be significant to the financial position and liquidity of SDG&E and Sempra.
SDG&E determined that none of its PPAs and tolling agreements resulted in SDG&E being the primary beneficiary of a VIE at December 31, 2022 and 2021. PPAs and tolling agreements that relate to SDG&E’s involvement with VIEs are primarily accounted for as finance leases. The carrying amounts of the assets and liabilities under these contracts are included in PP&E, net, and finance lease liabilities with balances of $i1,194
million and $i1,217 million at December 31, 2022 and 2021, 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.
Sempra Texas Utilities
Oncor Holdings is a VIE. Sempra is not the primary beneficiary of this VIE because of the structural and operational ring-fencing and governance measures in place that prevent us from having the power to direct the significant activities of Oncor Holdings. As a result, we do not consolidate Oncor Holdings and instead account for our ownership interest as an equity method investment. See Note 6 for additional information about our equity method investment in Oncor Holdings and restrictions on our ability to influence its activities. Our maximum exposure to loss, which fluctuates over time, from our interest in Oncor Holdings does not exceed the carrying value of our investment, which was $i13,665
million and $i12,947 million at December 31, 2022 and 2021, respectively.
Sempra Infrastructure
Cameron LNG JV
Cameron LNG JV is a VIE principally due to contractual provisions that transfer certain risks to customers. Sempra is not the primary beneficiary of this VIE because we do not have the power to direct the most significant activities of Cameron
LNG JV,
including LNG production and operation and maintenance activities at the liquefaction facility. Therefore, we account for our investment in Cameron LNG JV under the equity method. The carrying value of our investment, including amounts recognized in AOCI related to interest-rate cash flow hedges at Cameron LNG JV, was $i886
million and $i514 million at December 31, 2022 and 2021, respectively. Our maximum exposure to loss, which fluctuates over time, includes the carrying value of our investment and our obligation under the SDSRA, which we discuss in Note 6.
CFIN
As we discuss in Note 6, in July 2020, Sempra entered into a Support Agreement for the benefit of CFIN, which is a VIE. Sempra is not the primary beneficiary
of this VIE because we do not have the power to direct the most significant activities of CFIN, including modification, prepayment, and refinance decisions related to the financing arrangement with external lenders and Cameron LNG JV’s four project owners as well as the ability to determine and enforce remedies in the event of default. The conditional obligations of the Support Agreement represent a variable interest that we measure at fair value on a recurring basis (see Note 12). Sempra’s maximum exposure to loss under the terms of the Support Agreement is$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 is the primary beneficiary of this VIE because we have the power to direct the development activities related to the construction of the liquefaction facility, which we consider to be the most significant activities of ECA LNG Phase 1 during the construction phase of its natural gas liquefaction project. As a result, we consolidate ECA LNG Phase 1. Sempra consolidated $i1,099
million and $i632 million of assets at December 31, 2022 and 2021, respectively, consisting primarily of PP&E, net, and Accounts Receivable – Other attributable to ECA LNG Phase 1 that could be used only to settle obligations of this VIE and that are not available to settle obligations of Sempra, and $i685
million and $i455 million of liabilities at December 31, 2022 and 2021, respectively, consisting primarily of long-term debt, short-term debt and accounts payable attributable to ECA LNG Phase 1 for which creditors do not have recourse to the general credit of Sempra. Additionally, as we discuss in Note 7, IEnova and TotalEnergies SE have provided guarantees for i83.4%
and i16.6%, respectively, of the loan facility supporting construction of the liquefaction facility.
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 using the present value of the obligation at the time the asset is placed into service, and recognize that cost over the life of the related asset by depreciating the asset retirement cost and accreting the obligation until the liability is settled. Our rate-regulated entities record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through
the rate-making process.
We have recorded AROs related to various assets, including:
SDG&E and SoCalGas
▪fuel and storage tanks
▪natural gas transmission and distribution systems
▪hazardous waste storage facilities
▪asbestos-containing construction materials
SDG&E
▪nuclear power facilities
▪electric transmission and distribution systems
▪energy
storage systems
▪power generation plants
SoCalGas
▪underground natural gas storage facilities and wells
▪natural gas
transportation and distribution systems
▪LPG terminal
▪refined products terminals
▪power generation plants
i
The changes in AROs are as follows:
CHANGES
IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
Sempra
SDG&E
SoCalGas
2022
2021
2020
2022
2021
2020
2022
2021
2020
Balance
as of January 1(1)
$
i3,538
$
i3,289
$
i3,083
$
i890
$
i876
$
i866
$
i2,582
$
i2,368
$
i2,177
Accretion
expense
i141
i133
i127
i37
i38
i39
i101
i92
i86
Liabilities
incurred and acquired
i21
i20
i2
i6
i2
i—
i—
i—
i—
Payments
(i57)
(i63)
(i63)
(i54)
(i60)
(i60)
(i3)
(i3)
(i2)
Revisions(2)
i69
i159
i140
i8
i34
i31
i63
i125
i107
Balance
at December 31(1)
$
i3,712
$
i3,538
$
i3,289
$
i887
$
i890
$
i876
$
i2,743
$
i2,582
$
i2,368
(1) Current
portion of the ARO for Sempra is included in Other Current Liabilities on the Consolidated Balance Sheets.
(2) SDG&E’s change in ARO in 2022 and 2021 includes $i1 and $i22,
respectively, due to a revised estimate that is offset in noncurrent Regulatory Liabilities and Regulatory Assets, respectively, 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 if:
▪information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and
▪the amount of the loss or a range of possible losses can be reasonably estimated.
We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.
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.
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 PBOP plans
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.
(1) All
amounts are net of income tax, if subject to tax, and after NCI.
(2) Includes discontinued operations in 2020.
(3)Pension and PBOP and Total AOCI include $i6 in transfers of liabilities from SDG&E to SoCalGas and $i3
in transfers of liabilities from SDG&E to Sempra in 2020.
(4) Total AOCI includes $(i28) of foreign currency translation adjustments and $(i16)
of financial instruments associated with the IEnova exchange and cash tender offers in 2021. Total AOCI includes $(i4) of foreign currency translation adjustments and $(i3)
of financial instruments associated with IEnova’s repurchases of NCI in 2020. We discuss these transactions below in “Other Noncontrolling Interests – Sempra Infrastructure.” These transactions do not impact the Consolidated Statements of Comprehensive Income (Loss).
(5) Total AOCI includes $i19 of foreign currency translation adjustments and $i47
of financial instruments associated with the sale of NCI to KKR in 2021. We discuss this transaction below in “Other Noncontrolling Interests – Sempra Infrastructure.” This transaction does not impact the Consolidated Statement of Comprehensive Income (Loss).
(6)Total AOCI includes $i9 of foreign currency translation adjustments associated with the sale of NCI to ADIA in 2022. We discuss
this transaction below in “Other Noncontrolling Interests – Sempra Infrastructure.” This transaction does not impact the Consolidated Statement of Comprehensive Income (Loss).
Ownership interests in a consolidated entity that are held by unconsolidated owners are accounted for and reported as NCI.
SoCalGas Preferred Stock
The preferred stock at SoCalGas is presented at Sempra as NCI. Sempra records charges against income related to NCI for preferred dividends declared by SoCalGas. We provide additional information regarding SoCalGas’ preferred stock in Note 13.
Other Noncontrolling Interests
i
The
following table provides information about NCI held by others in subsidiaries or entities consolidated by us and recorded in Other Noncontrolling Interests in Total Equity on Sempra’s Consolidated Balance Sheets.
OTHER NONCONTROLLING INTERESTS
(Dollars in millions)
Percent
ownership held by noncontrolling interests
(1) SI
Partners has subsidiaries with NCI held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.
/
Sempra Infrastructure
Sale of NCI in SI Partners to KKR. On October 1, 2021, Sempra, its wholly owned subsidiary, SI Partners (formerly Sempra Global), and KKR consummated the transactions contemplated under a purchase and contribution agreement dated April 4, 2021 (as amended prior to closing, the KKR Purchase Agreement). Pursuant to the KKR Purchase Agreement, KKR acquired newly designated Class A Units representing a i20%
NCI in SI Partners for a purchase price of $i3.4 billion, including post-closing adjustments. As a result of this sale, we recorded a $i1.3
billion increase in equity held by NCI and an increase in Sempra’s shareholders’ equity of $i1.4 billion, net of $i173
million in transaction costs and $i490 million in tax impacts, including the tax effect of the sale and changes to a deferred income tax liability related to outside basis differences in SI Partners. Transaction costs include $i149
million paid to KKR for reimbursement of certain expenses that KKR incurred in connection with closing the transaction.
Prior to the closing of the transactions contemplated under the KKR Purchase Agreement on October 1, 2021, we completed an internal legal reorganization to consolidate the assets of Sempra LNG Holding, LP and our ownership of IEnova under Sempra Global, which was renamed SI Partners.
Pursuant to the KKR Purchase Agreement, we have agreed to indemnify SI Partners for, among other things, certain losses arising from liabilities of SI Partners and its subsidiaries to the extent not primarily relating to the undertaking of the business of SI Partners, and we have agreed to indemnify KKR for losses attributable to pre-closing taxes.
SI Partners has two authorized classes of
units, designated as “Class A Units” (which are common voting units) and “Sole Risk Interests.” If KKR approves our request that a project not be pursued jointly, or if KKR decides not to participate in any proposed project for which we nevertheless desire to make a positive final investment decision, we may proceed with such project either independently through a different investment vehicle or as a “Sole Risk Project” within SI Partners and receive Sole Risk Interests in respect thereof. Sole Risk Projects are separated from other SI Partners projects and are conducted at our sole cost, expense and liability and we receive, through the acquisition of Sole Risk Interests, any economic and other benefits from such projects. KKR is not entitled to any benefits or rights in respect of any Sole Risk Project. The Guaymas-El Oro segment of the Sonora pipeline currently constitutes a Sole Risk Project. Until a specified date, KKR has certain discretionary
rights to cause the Guaymas-El Oro segment of the Sonora pipeline to cease to be a Sole Risk Project and be pursued jointly within SI Partners.
At the closing of the sale of NCI in SI Partners to KKR, Sempra and KKR entered into a limited partnership agreement (the LP Agreement), which governs our and their respective rights and obligations in respect of our ownership interests in SI Partners. The LP Agreement contains certain default remedies if we or KKR fails to fund any amounts required to be funded under the LP Agreement. The LP Agreement also requires that SI Partners distribute to us and to KKR at least i85%
of distributable cash of SI Partners and its subsidiaries on a quarterly basis, subject to certain exceptions and reserves. Generally, distributions from SI
Partners are made to us and KKR on a pro rata basis in accordance with our and their respective ownership interests in SI Partners. However, KKR is entitled to certain priority distributions in the event of material deviations between certain specified projected cash flows and actual cash flows. Additionally, KKR is entitled to certain priority
distributions in the event a specified project that reaches a positive final investment decision does not have projected internal rates of return over a specified threshold or in the event we have not made a positive final investment decision by a certain date on specified LNG projects that are currently in development.
In addition, under the LP Agreement, both parties are granted customary registration rights in the event of an initial public offering of SI Partners, which is subject to certain consent rights of KKR.
At the closing of the transactions contemplated under the KKR Purchase Agreement, SI Partners entered into a management agreement with Sempra to engage Sempra for certain staffing and general and administrative services. The management agreement governs the services that Sempra provides to SI Partners and the charges associated with those services.
Sale
of NCI in SI Partners to ADIA. On June 1, 2022, Sempra and ADIA consummated the transaction contemplated under a purchase and sale agreement dated December 21, 2021 (the ADIA Purchase Agreement). Pursuant to the ADIA Purchase Agreement, ADIA acquired Class A Units representing a i10% NCI in SI Partners for a purchase price of $i1.7
billion. Following the closing of the transaction, Sempra, KKR and ADIA directly or indirectly own i70%, i20%, and i10%,
respectively, of the outstanding Class A Units of SI Partners, which excludes the non-voting Sole Risk Interests held only by Sempra. As a result of this sale to ADIA, we recorded a $i709 million increase in equity held by NCI and an increase in Sempra’s shareholders’ equity of $i710 million,
net of $i12 million in transaction costs and $i300 million in tax impacts.
Transaction costs include $i10 million paid to ADIA for reimbursement of certain expenses that ADIA incurred in connection with closing the transaction.
At the closing of the sales of NCI in SI Partners to KKR and ADIA, SI Partners indirectly owned i99.9%
of the outstanding shares of IEnova. To the extent we acquire additional shares of IEnova after each respective closing, such additional shares will be acquired by SI Partners, and KKR and ADIA will provide i20% and i10%,
respectively, of the funding.
At the closing, KKR and ADIA (the Minority Partners) and Sempra entered into a second amended and restated agreement of limited partnership of SI Partners (the Amended LP Agreement), which governs their respective rights and obligations in respect of their ownership of SI Partners. Under the Amended LP Agreement, matters are decided generally by majority vote and the managers designated by Sempra, KKR and ADIA each, as a group, have voting power equivalent to the ownership percentage of their respective designating limited partner. Sempra maintains control of SI Partners. However, SI Partners and its controlled subsidiaries are prohibited from taking certain limited actions without the prior written approval of the Minority Partners (subject to each Minority Partner maintaining certain ownership thresholds in SI Partners). The minority protections held by ADIA constitute a subset of the minority
protections granted to KKR.
The terms of the Amended LP Agreement applicable to ADIA in relation to capital contributions and distributions are generally consistent with those granted to KKR, with adjustments and limitations to take into account ADIA’s relative ownership percentage, including limiting ADIA’s priority distribution rights to the failure of certain proposed projects to receive a positive final investment decision by a certain date or to achieve specified thresholds of projected internal rates of return or leverage. The transfer rights and restrictions and registration rights in the Amended LP Agreement applicable to ADIA are also generally consistent with those granted to KKR, with adjustments and limitations to take into account ADIA’s relative ownership percentage, including a general restriction on ADIA transferring its interests in SI Partners to third parties (other than pursuant to certain specified permitted
transfers) for a specified period following its entry into the Amended LP Agreement.
SI Partners Subsidiaries. In May 2021, we acquired i381,015,194 publicly owned shares of IEnova in exchange for i12,306,777
newly issued shares of our common stock upon completion of our exchange offer launched in the U.S. and Mexico, which increased our ownership interest in IEnova from i70.2% to i96.4%.
Upon completing the exchange offer, Sempra’s common stock became listed on the Mexican Stock Exchange under the trading symbol SRE.MX. We acquired the IEnova shares at an exchange ratio of i0.0323 shares of our common stock for each one IEnova share. In connection with the exchange offer, we recorded a $i1.4
billion decrease in equity held by NCI and an increase in Sempra’s shareholders’ equity of $i1.4 billion, net of $i12
million in transactions costs.
In September 2021, we acquired i51,014,545 publicly owned shares of IEnova for i4.0 billion Mexican pesos (approximately $i202
million in U.S. dollars) in cash upon completion of our tender offer launched in the U.S. and Mexico in August 2021, which increased our ownership interest in IEnova from i96.4% to i99.9%.
We acquired these IEnova shares at a price of i78.97 Mexican pesos per share (approximately $i3.95 per share in U.S. dollars). In connection with the cash tender offer, we recorded a $i188
million decrease in equity held by NCI and a decrease in Sempra’s shareholders’ equity of $i17 million, including $i4
million in transaction costs.
As a result of the increase in our ownership interest in IEnova, we recorded an increase in Sempra’s shareholders’ equity of $i72
million offset by a deferred income tax asset related to the outside basis difference in IEnova’s shares. Upon completing the sale of a i20% NCI in SI Partners to KKR in October 2021, which we discuss above, we recorded $i72
million in net income tax expense related to the utilization of this deferred income tax asset.
Following the exchange offer and the cash tender offer, IEnova’s shares were delisted from the Mexican Stock Exchange effective October 15, 2021. In connection with the delisting, we are maintaining a trust for the purpose of purchasing the i1,212,981 IEnova shares that remained publicly owned as of the completion of
the cash tender offer for i78.97 Mexican pesos per share, the same price per share that was offered in our cash tender offer. The trust was to be in place through the earlier of April 14, 2022 or the date on which we acquired all the remaining publicly owned IEnova shares. On April 13, 2022, the term of the trust was amended so that it will remain in place until we terminate it, subject to any maximum term under applicable Mexican law. As of February 21, 2023, an aggregate of i890,170
of the remaining publicly owned IEnova shares had been acquired by such trust.
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’s ownership interest in IEnova from i66.6% to i70.2%.
In 2020, Sempra Infrastructure 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 Sempra Infrastructure is developing a terminal in the vicinity of Manzanillo for the receipt, storage and delivery of refined products. In July 2021, Sempra Infrastructure acquired the remaining i17.5% interest held by NCI in ICM Ventures Holdings B.V. for $i7 million.
In
2020, an affiliate of TotalEnergies SE acquired a i16.6% ownership interest in ECA LNG Phase 1.
In 2020, Sempra Infrastructure purchased for $i7 million
the i24.6% minority interest in Liberty Gas Storage LLC, increasing Sempra Infrastructure’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 Infrastructure to equity. As a result of the purchase, we recorded an increase in Sempra’s shareholders’ equity of $i2 million
for the difference between the carrying value and fair value related to the change in ownership.
Parent and Other
As we discuss in Note 5, in December 2021, Parent and other sold its equity interest in PXiSE.
Discontinued Operations
As we discuss in Note 5, we completed the sales of our equity interests in our Peruvian and Chilean businesses in 2020. The minority interests in Luz del Sur and Tecsur were deconsolidated upon the sale of our Peruvian businesses in April 2020, and the minority interests in Chilquinta Energía and its subsidiaries were deconsolidated upon the sale of our Chilean businesses in June 2020.
REVENUES
See
Note 3 for a description of significant accounting policies for revenues.
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 2020) use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings, but are reflected in OCI and in AOCI.
Cash
flows of these consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash on Sempra’s Consolidated Statements of Cash Flows.
Foreign currency transaction losses in a currency other than Sempra Infrastructure’s functional currency were $i24 million,
$i18 million and $i25 million for the years ended
December 31, 2022, 2021 and 2020, respectively, and are included in Other Income (Expense), Net, on Sempra’s Consolidated Statements of Operations. Foreign currency transaction gains (losses) in a currency other than the functional currencies of our operations in South America are included in discontinued operations.
Total
due to unconsolidated affiliates – noncurrent
$
(i301)
$
(i287)
SDG&E:
Sempra
$
(i49)
$
(i40)
SoCalGas
(i72)
(i48)
Various
affiliates
(i14)
(i9)
Total due to unconsolidated
affiliates – current
$
(i135)
$
(i97)
Income
taxes due from Sempra(3)
$
i10
$
i19
SoCalGas:
SDG&E
$
i72
$
i48
Various
affiliates
i5
i1
Total due
from unconsolidated affiliates – current
$
i77
$
i49
Sempra
$
(i36)
$
(i36)
Total
due to unconsolidated affiliates – current
$
(i36)
$
(i36)
Income
taxes due (to) from Sempra(3)
$
(i16)
$
i6
(1)At
December 31, 2021, represents a Mexican peso-denominated revolving line of credit for up to i14.2 billion Mexican pesos or approximately $i691
U.S. dollar-equivalent at a variable interest rate based on the 91-day Interbank Equilibrium Interest Rate plus i220 bps (i8.06% at December 31,
2021). At December 31, 2021, $i2 of accrued interest receivable is included in Due from Unconsolidated Affiliates – Current. In March 2022, Sempra Infrastructure amended and restated the revolving line of credit to a U.S. dollar-denominated note in the amount of $i625
at a variable interest rate based on the adjusted 1-month SOFR plus i180 bps and extended the maturity date to March 15, 2023. In July 2022, this note receivable was paid in full.
(2)U.S. dollar-denominated loans at fixed interest rates. Amounts include principal balances plus accumulated interest outstanding.
(3) SDG&E and SoCalGas are included
in the consolidated income tax return of Sempra, and their respective income tax expense is computed as an amount equal to that which would result from each company having always filed a separate return. Amounts include current and noncurrent income taxes due to/from Sempra.
(1) Includes
net commodity costs from natural gas transactions with unconsolidated affiliates.
Sempra California
Sempra, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time-to-time, SDG&E and SoCalGas may make short-term advances of surplus cash to Sempra at interest rates based on the federal funds effective rate plus a margin of i13 to i20
bps, depending on the loan balance.
SoCalGas provides natural gas transportation and storage services to SDG&E and charges SDG&E for such services monthly. SoCalGas records revenues and SDG&E records a corresponding amount to cost of sales.
SDG&E and SoCalGas charge one another, as well as other Sempra affiliates, for shared asset depreciation. SoCalGas and SDG&E record revenues and the affiliates record corresponding amounts to O&M.
The natural gas supply for SDG&E’s and SoCalGas’ core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service; therefore, revenues and costs related to SDG&E are presented net in
SoCalGas’ Statements of Operations.
SDG&E has a i20-year contract for up to i155 MW of renewable power supplied from the ESJ wind power generation facility. Prior to March 2021, ESJ was a i50%
owned and unconsolidated JV of Sempra Infrastructure. In March 2021, Sempra Infrastructure completed the acquisition of the remaining i50% interest in ESJ and ESJ became a consolidated subsidiary of Sempra. A second i20-year contract between SDG&E and ESJ
for up to i108 MW of renewable power supplied from the same facility commenced in January 2022.
Sempra Infrastructure
Sempra Infrastructure provides maintenance and administrative services to TAG Pipelines Norte, S. de. R.L. de C.V. Additionally, Sempra Infrastructure subleases office space for personnel to TAG Pipelines Norte, S. de. R.L. de C.V. and TAG.
Sempra Infrastructure has agreements with Cameron LNG JV to provide certain business services and project development
services related to the Cameron LNG Phase 2 project. Sempra Infrastructure had an agreement to provide transportation services to Cameron LNG JV for capacity on the Cameron Interstate Pipeline through August 2020, when Cameron LNG JV achieved commercial operations of Train 3 of its Phase 1 project.
Sempra provided guarantees related to Cameron LNG JV’s construction-period debt that were terminated in March 2021, as well as guarantees related to Cameron LNG JV’s SDSRA and CFIN’s Support Agreement that remain outstanding. We discuss these guarantees in Note 6.
RESTRICTED NET ASSETS
Sempra
As we discuss below, SDG&E, SoCalGas and certain
other Sempra subsidiaries have restrictions on the amount of funds that can be transferred to Sempra by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally,
certain other Sempra subsidiaries are subject to various financial and other covenants and other restrictions contained in debt and credit agreements (described in Note 7) and in other agreements that limit the amount of funds that can be transferred to Sempra. At December 31,
2022, Sempra was in compliance with all covenants related to its debt agreements.
At December 31, 2022, the amount of restricted net assets of consolidated entities of Sempra, including SDG&E and SoCalGas discussed below, that may not be distributed to Sempra in the form of a loan or dividend is $i15.3 billion. Additionally, the amount of restricted net assets of our unconsolidated
entities is $i14.0 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries can provide to Sempra, we do not believe these restrictions will have a significant impact on our ability to access cash to pay dividends and fund operating needs.
As we discuss in Note 6, $i2.0
billion of Sempra’s retained earnings represents undistributed earnings of equity method investments at December 31, 2022.
Sempra California
The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts available for dividends and loans to Sempra. At December 31, 2022, Sempra could have received combined loans and dividends of approximately $i504
million from SDG&E and approximately $i347 million from SoCalGas.
The payment and amount of future dividends by SDG&E and SoCalGas are at the discretion of their respective boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra from either utility:
▪The
CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC-authorized percentage of each entity’s authorized capital structure. The authorized percentage at December 31, 2022 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, 2022, SDG&E’s restricted net assets were $i8.6
billion and SoCalGas’ restricted net assets were $i6.4 billion, which could not be transferred to Sempra.
Sempra Texas Utilities
Sempra 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 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, 2022.
▪If the credit rating on Oncor’s senior secured debt by any of the Rating Agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. At December 31, 2022, 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, 2022, Oncor was in compliance with these covenants.
Based on these restrictions, at December 31, 2022, Oncor’s restricted net assets were $i13.5
billion, which could not be transferred to its owners.
Sempra 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 i60%
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, 2022, Sharyland Utilities was in compliance with these and all other covenants.
Based on these restrictions, at December 31, 2022, Sharyland Utilities’ restricted net assets were $i105 million, which could not be transferred to its owners.
Sempra
Infrastructure
Significant restrictions at Sempra Infrastructure include:
▪Partnerships and JVs at Sempra Infrastructure may not pay dividends or make other distributions (except for contractual payments) without the consent of the partners.
▪Sempra Infrastructure has an equity method investment in Cameron LNG JV, which has debt agreements that require the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The debt agreements require the JV to maintain reserve accounts in order to pay the project debt service, and also contain restrictions related to the payment of dividends and other distributions to the members of the JV.
Pursuant
to the transfer restriction agreement under the debt agreements, Sempra 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 controlled (but not necessarily wholly owned) subsidiary must directly own i50.2%
of the membership interests of Cameron LNG JV.
To support Cameron LNG JV’s obligations under its debt agreements, Cameron LNG JV has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG JV were pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG JV’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG JV by Sempra and the other project partners.
Under these restrictions, net assets of Cameron LNG JV of approximately $i396
million are restricted at December 31, 2022.
▪Mexico requires domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $i239 million at Sempra Infrastructure’s consolidated Mexican subsidiaries at December 31, 2022.
▪IEnova
has restrictions under trust and debt agreements related to pipeline projects to pay for rights-of-way, license fees, permits, topographic surveys and other costs. Under these restrictions, net assets totaling $i2 million are restricted at December 31, 2022.
▪TAG, a i50%
owned and unconsolidated JV of Sempra Infrastructure, has a long-term debt agreement that requires it to maintain a reserve account to pay the projects’ debt. Under these restrictions, net assets totaling $i64 million are restricted at December 31, 2022.
▪As we discuss in Note 16, Sempra Infrastructure drew against and fully exhausted Gazprom’s letters of
credit in April 2022 due to Gazprom’s non-renewal of such letters of credit as required under its LNG storage and regasification agreement. As a result, Sempra Infrastructure has restricted cash for funds drawn from the letters of credit. Under these restrictions, net assets totaling $i89 million are restricted at December 31, 2022.
Based on these restrictions, at December 31,
2022, Sempra Infrastructure’s restricted net assets of its consolidated and unconsolidated entities were $i330 million and $i460
million, respectively, which could not be transferred to its owners.
OTHER INCOME (EXPENSE), NET
iOther Income (Expense), Net on the Consolidated Statements of Operations consists of the following:
Allowance for equity funds used during construction
$
i143
$
i133
$
i128
Investment
(losses) gains, net(1)
(i42)
i50
i41
Gains
(losses) on interest rate and foreign exchange instruments, net
i11
(i28)
(i67)
Foreign
currency transaction losses, net(2)
(i24)
(i18)
(i25)
Non-service
component of net periodic benefit cost
(i59)
(i67)
(i102)
Interest
on regulatory balancing accounts, net
i26
i6
i14
Sundry,
net
(i31)
(i18)
(i37)
Total
$
i24
$
i58
$
(i48)
SDG&E:
Allowance
for equity funds used during construction
$
i88
$
i81
$
i79
Non-service
component of net periodic benefit cost
(i11)
(i13)
(i20)
Interest
on regulatory balancing accounts, net
i18
i6
i9
Sundry,
net
(i3)
(i10)
(i16)
Total
$
i92
$
i64
$
i52
SoCalGas:
Allowance
for equity funds used during construction
$
i55
$
i48
$
i41
Non-service
component of net periodic benefit cost
(i42)
(i40)
(i54)
Interest
on regulatory balancing accounts, net
i8
i—
i5
Sundry,
net
(i29)
(i22)
(i20)
Total
$
(i8)
$
(i14)
$
(i28)
(1)Represents
net investment (losses) gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are offset by corresponding changes in compensation expense related to the plans, recorded in O&M on the Consolidated Statements of Operations.
(2) Includes losses of $i11, $i23
and $i42 in 2022, 2021 and 2020, respectively, from translation to U.S. dollars of a Mexican peso-denominated loan to IMG, which are offset by corresponding amounts included in Equity Earnings on the Consolidated Statements of Operations.
NOTE
2. iNEW ACCOUNTING STANDARDS
We describe below recent accounting pronouncements that have had or may have a significant effect on our results of operations, financial condition, cash flows or disclosures.
i
ASU
2020-06, “Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity”: ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. In addition to other changes, this standard amends ASC 470-20, “Debt with Conversion and Other Options,” by removing the accounting models for instruments with beneficial and cash conversion features. The standard also amends certain guidance in ASC 260, “Earnings Per Share,” for the computation of EPS for convertible instruments and contracts on an entity’s own equity. For public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. An entity can use either a full or modified retrospective approach to adopt ASU 2020-06 and must disclose,
in the period of adoption, EPS transition information about the effect of the change on affected per-share amounts. We adopted the standard on January 1, 2022 using a modified retrospective approach and the adoption did not materially impact our financial statements or per-share amounts.
ASU 2020-04, “Facilitation of the Effects of Reference Rate Reform on Financial Reporting” and ASU 2022-06, “Deferral of the Sunset Date of Topic 848”: ASU 2022-06 extends the time when entities can utilize the reference rate reform relief provided by ASU 2020-04 from December 31, 2022 to December 31, 2024. Under ASU 2020-04, we elected to apply certain optional expedients for contract modifications to financial instruments that were impacted by the discontinuance
of LIBOR. We will continue to apply various optional expedients for contract modifications for our financial instruments affected by the reference rate reform through December 31, 2024 as extended by ASU 2022-06. The application of these practical expedients does not impact our financial statements.
The following table disaggregates our revenues from contracts with customers by major service line and market and provides a reconciliation to total revenues by segment.
The majority of our revenue is recognized over time.
Revenues from contracts with customers 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 customers and invoices are issued 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. 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 respective 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 customer contracts vary. Typically, we have an unconditional right to customer payments, which are due after the performance obligation to the customer is satisfied. The term between invoicing and when payment is due is typically between 10 and 90 days.
We exclude sales and usage-based taxes from revenues. In addition, SDG&E
and SoCalGas pay franchise fees to operate in various municipalities. SDG&E and SoCalGas bill these franchise fees to their customers based on a CPUC-authorized rate. These franchise fees, which are required to be paid regardless of SDG&E’s and SoCalGas’ ability to collect from the customer, are accounted for on a gross basis and reflected in utilities revenues from contracts with customers and operating expense.
Utilities Revenues
Utilities revenues represent the majority of our consolidated revenues from contracts with customers and include:
▪The transmission, distribution and storage of natural gas at:
◦SDG&E
◦SoCalGas
◦Sempra
Infrastructure’s Ecogas
▪The generation, transmission and distribution of electricity at SDG&E.
Utilities revenues are derived from and recognized upon the delivery of natural gas or electricity services to customers. Amounts that we bill customers are based on tariffs set by regulators within the respective state or country. For SDG&E and SoCalGas, which follow the provisions of U.S. GAAP governing rate-regulated operations as we discuss in Note 1, amounts that we bill to customers also include adjustments for previously recognized regulatory revenues.
SDG&E, SoCalGas and Ecogas recognize revenues based on regulator-approved revenue requirements, which allow the utilities to recover their reasonable operating costs and provides the opportunity to realize their authorized rates of return on their
investments. While SDG&E’s and SoCalGas’ revenues are not affected by actual sales volumes, the pattern of their revenue recognition during the year is affected by seasonality. SDG&E and SoCalGas recognize annual authorized revenue for customers using seasonal factors established in applicable proceedings. This generally results in a significant portion of operating revenues being recognized in the third quarter of each year for SDG&E and in the first and fourth quarters of each year for SoCalGas.
SDG&E has an arrangement to provide the California ISO with the ability to control its high-voltage transmission lines for prices approved by the FERC. Revenue is recognized over time as access is provided to the California ISO.
Factors that can affect the amount, timing and uncertainty of revenues and cash flows include weather, seasonality and timing of customer billings,
which may result in unbilled revenues that can vary significantly from month to month and generally approximate one-half month’s deliveries.
SDG&E and SoCalGas recognize revenues from the sale of allocated California GHG emission allowances at quarterly auctions administered by CARB. GHG allowances are delivered to CARB in advance of the quarterly auctions, and SDG&E and SoCalGas have the right to payment when the GHG allowances are sold at auction. GHG revenue is recognized on a point in time basis within the quarter the auction is held. SDG&E and SoCalGas balance costs and revenues associated with the GHG program through regulatory balancing accounts.
Revenues at Sempra Infrastructure typically represent revenues from long-term, U.S. dollar-based contracts with customers for the sale of natural gas and LNG, as well as storage and transportation of natural gas. Invoiced amounts are based on the volume of natural gas delivered and contracted prices.
We recognize storage revenue from firm capacity reservation agreements, under which we collect a fee for reserving storage capacity for customers in our storage facilities. Under these firm agreements, customers pay a monthly fixed reservation fee based on the storage capacity reserved rather than the actual volumes stored. For the fixed-fee component, revenue
is recognized on a straight-line basis over the term of the contract. We bill customers for any capacity used in excess of the contracted capacity and such revenues are recognized in the month of occurrence. We also recognize revenue for interruptible storage services.
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 impacts and the actual quantity of commodity transported.
Sempra Infrastructure develops, invests in and operates 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, 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.
TdM is a natural gas-fired power plant that generates revenues from selling electricity and/or resource adequacy to the California
ISO and to governmental, public utility and wholesale power marketing entities, as the power is delivered at the interconnection point.
Sempra Infrastructure sells natural gas to the CFE and other customers under supply agreements. Sempra Infrastructure recognizes the revenue from the sale of natural gas upon transfer of the natural gas via pipelines to customers at the agreed upon delivery points, and in the case of the CFE, at its thermoelectric power plants.
Remaining Performance Obligations
We do not disclose information about remaining performance obligations for (a) contracts with an original expected length of one year or less, (b) variable consideration recognized at the amount at which we have the right to invoice for services performed, or (c) variable consideration allocated to wholly unsatisfied performance obligations.
iFor
contracts greater than one year, at December 31, 2022, we expect to recognize revenue related to the fixed fee component of the consideration as shown below. Sempra’s remaining performance obligations primarily relate to capacity agreements for natural gas storage and transportation at Sempra Infrastructure and transmission line projects at SDG&E. SoCalGas did not have any remaining performance obligations at December 31, 2022.
REMAINING PERFORMANCE OBLIGATIONS(1)
(Dollars
in millions)
Sempra
SDG&E
2023
$
i396
$
i4
2024
i361
i4
2025
i359
i4
2026
i358
i4
2027
i355
i4
Thereafter
i4,134
i60
Total
revenues to be recognized
$
i5,963
$
i80
(1) Excludes
intercompany transactions.
Contract Liabilities from Revenues from Contracts with Customers
From time to time, we receive payments in advance of satisfying the performance obligations associated with customer contracts. We defer such revenues as contract liabilities and recognize them in earnings as the performance obligations are satisfied.
Activities
within Sempra’s and SDG&E’s contract liabilities are presented below. There were no contract liabilities at SoCalGas in 2022, 2021 or 2020. As we discuss in Note 16, Sempra Infrastructure drew against and fully exhausted Gazprom’s letters of credit in April 2022 due to Gazprom’s non-renewal of such letters of credit as required under its LNG storage and regasification agreement. Sempra Infrastructure recorded a contract liability for the funds drawn from the letters of credit as payments received in advance. Gazprom did not pay its invoices from March 2022 through July 2022, so funds drawn from the letters of credit were used to fully offset such nonpayment, which have been reflected as revenue from performance obligations satisfied during the reporting period.
CONTRACT
LIABILITIES
(Dollars in millions)
2022
2021
2020
Sempra:
Contract liabilities at January 1
$
(i278)
$
(i207)
$
(i163)
Revenue
from performance obligations satisfied during reporting period
i131
i52
i4
Payments
received in advance
(i105)
(i123)
(i48)
Contract
liabilities at December 31(1)
$
(i252)
$
(i278)
$
(i207)
SDG&E:
Contract
liabilities at January 1
$
(i83)
$
(i87)
$
(i91)
Revenue
from performance obligations satisfied during reporting period
i4
i4
i4
Contract
liabilities at December 31(2)
$
(i79)
$
(i83)
$
(i87)
(1)Balances at December 31, 2022, 2021 and 2020 include $i45, $i116
and $i52, respectively, in Other Current Liabilities and $i207, $i162
and $i155, respectively, in Deferred Credits and Other.
/
(2)Balances at December 31, 2022, 2021 and 2020 include $iii4//
in Other Current Liabilities and $i75, $i79 and $i83,
respectively, in Deferred Credits and Other.
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)At December 31, 2022 and 2021, includes $i72 and $i24, respectively, of receivables due from customers that were billed
on behalf of CCAs, which are not included in revenues.
(2)Amount is presented net of amounts due to unconsolidated affiliates on the Consolidated Balance Sheets, when right of offset exists.
(3)In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E and SoCalGas enrolled residential and small business customers with past-due balances in long-term repayment plans.
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 we discuss
above, the regulatory framework requires SDG&E and SoCalGas to recover authorized revenue based on estimated annual demand forecasts approved in regular proceedings before the CPUC. However, actual demand for natural gas and electricity will generally vary from CPUC-approved forecasted demand due to the impacts from weather volatility, energy efficiency programs, rooftop solar and other factors affecting consumption. The CPUC regulatory framework provides for SDG&E and SoCalGas to use a “decoupling” mechanism, which allows SDG&E and SoCalGas to record revenue shortfalls or excess revenues resulting from any difference between actual and forecasted demand to be recovered or refunded in authorized revenue in a subsequent period based on the nature of the account.
Incentive Mechanisms. The CPUC applies performance-based measures and incentive mechanisms to all California IOUs, under which
SDG&E and SoCalGas have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties.
Incentive awards are included in revenues when we receive required CPUC approval of the award, the timing of which may not be consistent from year to year. We would record penalties for results below the specified benchmarks against revenues when we believe it is probable that the CPUC would assess a penalty.
Other Cost-Based Regulatory Recovery
The CPUC, and the FERC as it relates to SDG&E, authorize SDG&E and SoCalGas to collect revenue requirements for operating costs and capital related costs (depreciation, taxes
and return on rate base) from customers, including:
▪costs to purchase natural gas and electricity;
▪costs associated with administering public purpose, demand response, and customer energy efficiency programs;
▪other programmatic activities, such as gas distribution, gas transmission, gas storage integrity management and wildfire mitigation; and
▪costs associated with third party liability insurance premiums.
Authorized costs are recovered as the commodity service is delivered. To the extent authorized amounts collected vary from actual costs, the differences are generally recovered or refunded in 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 of amounts accumulated for authorized programs, including limitations on the program’s total cost, revenue requirement limits or reviews of costs for reasonableness. These procedures could result in disallowances of recovery from ratepayers.
We discuss balancing accounts and their effects further in Note 4.
Other Revenues
Sempra Infrastructure generates lease revenues from certain of its natural gas and ethane pipelines,
compressor stations, LPG storage facilities, a rail facility and refined products terminals. We discuss the recognition of lease income in Note 16.
Sempra Infrastructure has an agreement with Tangguh PSC to supply LNG to the ECA Regas Facility. Under the terms of the agreement, Tangguh PSC must either deliver the contracted number of cargoes or pay a diversion fee for non-delivery of LNG cargoes.
Sempra Infrastructure also recognizes other revenues associated with derivatives related to the sales of natural gas and electricity under short-term and long-term contracts and into the spot market and other competitive markets. Revenues include the net
realized gains and losses on physical and derivative settlements and net unrealized gains and losses from the change in fair values of these derivatives.
NOTE
4. iREGULATORY MATTERS
REGULATORY ASSETS AND LIABILITIES
ii
We
show the details of regulatory assets and liabilities in the following table and discuss them below. With the exception of regulatory balancing accounts, we generally do not earn a return on our regulatory assets until such time as a related cash expenditure has been made. Upon the occurrence of a cash expenditure associated with a regulatory asset, the related amounts are recoverable through a regulatory account mechanism for which we earn a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate. The periods during which we recognize a regulatory asset while we do not earn a return vary by regulatory asset.
(1) At
December 31, 2022 and 2021, the noncurrent portion of regulatory balancing accounts – net undercollected for SDG&E was $i562 and $i358,
respectively, and for SoCalGas was $i692 and $i410, respectively.
(2) Includes regulatory assets
earning a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate.
▪Regulatory
assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. The related amounts are recovered in rates once these contracts are settled, generally within three years.
▪Deferred income taxes recoverable/refundable in rates are based on current regulatory ratemaking and income tax laws. SDG&E, SoCalGas and Sempra Infrastructure expect to recover/refund net regulatory assets/liabilities related to deferred income taxes over the lives of the assets, ranging from 5 to 69 years, that give rise to the related accumulated deferred income tax balances. Regulatory assets and liabilities
include excess deferred income taxes resulting from statutory income tax rate changes and certain income tax benefits and expenses associated with flow-through items, which we discuss in Note 8.
▪Regulatory assets/liabilities related to pension and PBOP plan obligations are offset by corresponding liabilities/assets. The assets are recovered in rates as the plans are funded.
▪The regulatory asset related to employee benefit costs represents our liability associated with long-term disability insurance that will be recovered from customers in future rates as expenditures are made.
▪Regulatory liabilities from removal obligations represent cumulative amounts collected in rates for future asset removal costs in excess of cumulative amounts incurred
(or paid).
▪Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.
▪The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining i47-year
period.
Regulatory Assets Earning a Return
▪Over- and undercollected regulatory balancing accounts and other regulatory assets, net, reflect the difference between customer billings and recorded or CPUC-authorized amounts. Depreciation, taxes and return on rate base may also be included in certain accounts. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. SDG&E and SoCalGas periodically make requests to the CPUC to true up their revenue requirement for amounts accumulated in the regulatory balancing accounts and in other regulatory assets, net. The CPUC may impose various review procedures before authorizing recovery or refund of amounts accumulated for authorized programs, including limitations on the program’s total cost, revenue requirement limits or reviews of costs
for reasonableness. These procedures could result in delays or disallowances of recovery from ratepayers.
Amortization expense on certain regulatory assets for the years ended December 31, 2022, 2021 and 2020 was $i11 million, $i10
million and $i9 million, respectively, at Sempra, $i5 million, $i5
million and $i4 million, respectively, at SDG&E, and $i6 million, $i5
million and $i5 million, respectively, at SoCalGas.
SEMPRA CALIFORNIA
COVID-19 Pandemic Protections
In connection with the COVID-19 pandemic and at the direction of the CPUC, SDG&E and SoCalGas implemented certain measures to assist customers, including suspending service disconnections due to nonpayment for all customers (except for SoCalGas’ noncore customers), waiving late payment fees, and offering flexible payment plans.
At the CPUC’s direction, SDG&E and SoCalGas enrolled residential and small business customers with past-due balances in long-term repayment plans.
In 2021, SDG&E and SoCalGas applied, on behalf of their customers, for financial assistance from the California Department of Community Services and Development under the 2021 California Arrearage Payment Program, which provided funds of $i63 million and $i79 million
for SDG&E and SoCalGas, respectively. In the first quarter of 2022, SDG&E and SoCalGas received and applied the amounts directly to eligible customer accounts to reduce past due balances. In June 2022, AB 205 was approved establishing, among other things, the 2022 California Arrearage Payment Program. In December 2022, SDG&E and SoCalGas received funding of $i51 million and $i59 million,
respectively, related to this program and, in January 2023, applied the amounts directly to eligible customer accounts to reduce past due balances.
SDG&E and SoCalGas have been authorized to track and request recovery of incremental costs associated with complying with customer protection measures implemented by the CPUC related to the COVID-19 pandemic, including costs associated with suspending service disconnections and uncollectible expenses that arise from customers’ failure to pay. SDG&E and SoCalGas expect to pursue recovery of small and medium-large commercial and industrial customers’ tracked costs in rates in future CPUC
proceedings,
which recovery is not assured. SDG&E and SoCalGas have each established a two-way balancing account to record the uncollectible expenses associated with residential customers’ inability to pay their electric or gas bills, including as a result of the relief from outstanding utility bill amounts provided under the Arrearage Management Payment Plan.
CPUC GRC
The CPUC uses GRCs to set revenues to allow SDG&E and SoCalGas to recover their reasonable operating costs and to provide the opportunity to realize their authorized rates of return on their investments.
In September 2019, the CPUC issued a final decision in the 2019 GRC approving SDG&E’s and SoCalGas’ test year revenues for 2019 and attrition year adjustments for 2020 and 2021, which was effective retroactively to January 1, 2019.
This is the first GRC that includes revenues authorized for risk assessment mitigation phase activities. In January 2020, the CPUC issued a final decision implementing a four-year GRC cycle for California IOUs. SDG&E and SoCalGas were directed to file a petition for modification to revise their 2019 GRC to add two additional attrition years, resulting in a transitional five-year GRC period (2019-2023). In May 2021, the CPUC issued a final decision approving SDG&E’s and SoCalGas’ request to continue their authorized post-test year mechanisms for 2022 and 2023. For SDG&E, the decision authorizes revenue requirement increases of $i87 million
(i3.92%) for 2022 and $i86 million
(i3.70%) for 2023. For SoCalGas, the decision authorizes revenue requirement increases of $i142 million
(i4.53%) for 2022 and $i130 million
(i3.97%) for 2023.
In May 2022, SDG&E and SoCalGas filed their 2024 GRC applications requesting CPUC approval of test year revenue requirements for 2024 and attrition year adjustments for 2025 through 2027. SDG&E and SoCalGas requested revenue requirements for 2024 of $i3.0
billion and $i4.4 billion, respectively. SDG&E and SoCalGas are proposing post-test year revenue requirement changes using various mechanisms that are estimated to result in annual increases of approximately i8%
to i11% at SDG&E and approximately i6% to i8%
at SoCalGas. In October 2022, the CPUC issued a scoping ruling that set a schedule for the proceeding, including the expected issuance of a proposed decision in the second quarter of 2024. SDG&E and SoCalGas expect the final decision will be effective retroactive to January 1, 2024. SDG&E expects to submit separate requests in its GRC for review and recovery of its wildfire mitigation plan costs in mid-2023 for costs incurred from 2019 through 2022 and in mid-2024 for costs incurred in 2023.
CPUC Cost of Capital
A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized return on rate base. The CCM applies in the interim years between required cost of capital applications and considers changes in the cost of capital based on changes in interest rates based on the applicable utility
bond index published by Moody’s (the CCM benchmark rate) for each 12-month period ending September 30 (the measurement period). The index applicable to SDG&E and SoCalGas is based on each utility’s credit rating. The CCM benchmark rate is the basis of comparison to determine if the CCM is triggered in each measurement period, which occurs if the change in the applicable Moody’s utility bond index relative to the CCM benchmark rate is larger than plus or minus i1.000% at the end of the measurement period. The CCM, if triggered, would automatically update the authorized cost of debt based on actual
costs and update the authorized ROE upward or downward by one-half of the difference between the CCM benchmark rate and the applicable Moody’s utility bond index. Alternatively, each of SDG&E and SoCalGas are permitted to file a cost of capital application in an interim year in which an extraordinary or catastrophic event materially impacts its cost of capital and affects utilities differently than the market as a whole to have its cost of capital determined in lieu of the CCM.
In December 2019, the CPUC approved the following cost of capital for SDG&E and SoCalGas that became effective on January 1, 2020 and remained in effect through December 31, 2022, subject to the CCM.
CPUC
AUTHORIZED COST OF CAPITAL FOR 2020 – 2022
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
%
For
the measurement period that ended September 30, 2021, SDG&E’s CCM benchmark rate was i4.498% based on Moody’s Baa- utility bond index and SoCalGas’ CCM benchmark rate was i4.029% based on Moody’s A- utility bond index. For this
measurement period, the CCM would have triggered for SDG&E if the CPUC determined that the CCM should be implemented because the average Moody’s Baa- utility bond index between October 1, 2020 and September 30, 2021 was i1.17%
below SDG&E’s CCM benchmark rate of i4.498%. In August 2021, SDG&E filed an application with the CPUC to update its cost of capital for 2022 due to the ongoing effects of the COVID-19 pandemic rather than have the CCM apply. In November 2022, the CPUC issued a final decision that found there was an extraordinary event, the CCM will be suspended for 2022 and SDG&E’s current authorized cost of capital for 2022 will be preserved.
In December 2022, the CPUC approved the following cost of capital for SDG&E and SoCalGas that became effective on January
1, 2023 and will remain in effect through December 31, 2025, subject to the CCM. The CPUC will open a second phase of this cost of capital proceeding to evaluate the CCM. For the measurement period that ends on September 30, 2023, SDG&E’s CCM benchmark rate is i4.367% based on Moody’s Baa- utility bond index and SoCalGas’ CCM benchmark rate is i4.074%
based on Moody’s A- utility bond index. SDG&E did not propose a 2023 cost of preferred equity in this proceeding. In January 2023, SDG&E filed an advice letter to continue the cost of preferred equity for test year 2023 at i6.22%, which the CPUC approved in February 2023.
CPUC
AUTHORIZED COST OF CAPITAL FOR 2023 – 2025
SDG&E
SoCalGas
Authorized weighting
Return on rate base
Weighted
return on
rate base(1)
Authorized weighting
Return on rate base
Weighted return on rate base
i45.25
%
i4.05
%
i1.83
%
Long-Term
Debt
i45.60
%
i4.07
%
i1.86
%
i2.75
i6.22
i0.17
Preferred
Equity
i2.40
i6.00
i0.14
i52.00
i9.95
i5.17
Common
Equity
i52.00
i9.80
i5.10
i100.00
%
i7.18
%
i100.00
%
i7.10
%
(1) Total
weighted return on rate base does not sum due to rounding differences.
SDG&E
FERC Rate Matters
SDG&E files separately with the FERC for its authorized ROE on FERC-regulated electric transmission operations and assets. SDG&E’s currently effective TO5 settlement provides 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 (the California ISO adder). If the FERC issues an order ruling that California IOUs are no longer eligible for the California ISO adder, SDG&E would refund the California ISO adder as of the refund effective date (June 1, 2019) if such a refund is determined to be required by the terms of the TO5 settlement. The TO5 term is effective June
1, 2019 and shall remain in effect until terminated by a notice provided at least six months before the end of the calendar year. Following such notice, SDG&E would file an updated rate request with an effective date of January 1 of the following year.
SOCALGAS
OSCs – Energy Efficiency and Advocacy
In October 2019, the CPUC issued an OSC to determine whether SoCalGas should be sanctioned for violation of certain CPUC code sections and orders relating to energy efficiency (EE) codes and standards advocacy activities, which were undertaken by SoCalGas following a CPUC decision disallowing SoCalGas’ future engagement in advocacy around such EE codes and standards. In March 2022, the CPUC issued a final decision that found that SoCalGas did undertake prohibited EE codes and standards advocacy activities using ratepayer funds. The
final decision imposed on SoCalGas a financial penalty of $i10 million; customer refunds for certain ratepayer expenditures and shareholder incentives that SoCalGas estimates will be negligible; and a prohibition from recovering from ratepayers costs of proposed codes and standards advocacy activities until SoCalGas demonstrates policies, practices and procedures that adhere to the CPUC’s intent for 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 activities in 2016 and 2017 (later expanded to include 2014 and 2015), whether its shareholders should bear the costs of those advocacy activities, and to address whether any other remedies are appropriate. In April 2022, the CPUC issued a final decision that found there were violations of certain legal principles and imposed a financial penalty of $i150,000.
NOTE 5. iACQUISITIONS,
DIVESTITURES AND DISCONTINUED OPERATIONS
ACQUISITION
Sempra Infrastructure
ESJ
In March 2021, Sempra Infrastructure completed the acquisition of Saavi Energía S. de R.L. de C.V.’s i50% equity interest in ESJ for a purchase price of $i65
million (net of $i14 million of acquired cash and cash equivalents) plus the assumption of $i277
million in debt (including $i94 million owed from ESJ to Sempra Infrastructure that eliminates upon consolidation). Sempra Infrastructure previously accounted for its i50%
interest in ESJ as an equity method investment. This acquisition increased Sempra Infrastructure’s ownership interest in ESJ from i50% to i100%.
We accounted for this asset acquisition using a cost accumulation model whereby the cost of the acquisition and carrying value of our previously held interest in ESJ ($i34 million) were allocated to assets acquired ($i458
million) and liabilities assumed ($i345 million) based on their relative fair values. ESJ owns a fully operating wind power generation facility with a nameplate capacity of i155
MW that is fully contracted by SDG&E under a long-term PPA. Sempra Infrastructure recorded a $i190 million intangible asset for the relative fair value of the PPA that will be amortized over a period of i14
years against revenues. On January 15, 2022, ESJ completed construction and began commercial operation of a second wind power generation facility with a nameplate capacity of i108 MW that is also fully contracted by SDG&E under a long-term PPA.
DIVESTITURE
Parent and Other
PXiSE
In December 2021, Parent and other completed the sale of its i80%
interest in PXiSE for total cash proceeds of $i38 million, net of transaction costs totaling $i4 million,
and recorded a $i36 million ($i26 million
after tax) gain, which is included in Gain (Loss) on Sale of Assets on Sempra’s Consolidated Statement of Operations.
DISCONTINUED OPERATIONS
In January 2019, our board of directors approved a plan to sell our South American businesses. We present these businesses, which previously constituted the Sempra South American Utilities segment, and certain activities associated with those businesses as discontinued operations.
In April 2020, we completed the sale of our equity interests in our Peruvian businesses, including our 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).
In the year ended December 31, 2020, the pretax gains from the sales of our South American businesses are included in Gain on Sale of Discontinued Operations in the table below and the after-tax gains are included in Income from Discontinued Operations, Net of Income Tax, on Sempra’s Consolidated Statement of Operations.
Income from discontinued operations, net of income tax
i1,850
Earnings
attributable to noncontrolling interests
(i10)
Earnings from discontinued operations attributable to common shares
$
i1,840
(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.
/
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 Sempra’s Consolidated Statement 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’s income tax on earnings from these equity method investees, other than Oncor Holdings as we discuss below, is included in Income Tax Expense on the Consolidated Statements of Operations. Our foreign equity method investees are generally corporations whose operations are taxable on a standalone basis in the countries in which they operate, and we recognize our equity in such income or loss net of investee income tax. See Note 8 for information on how equity earnings and losses before income taxes are factored into the calculations of our pretax income or loss and ETR.
(2) The carrying value of our equity method investment is $i2,856 and $i2,844
higher than the underlying equity in the net assets of the investee at December 31, 2022 and 2021, respectively, due to $ii2,868/
of equity method goodwill and $ii69/
in basis differences in AOCI, offset by $i81 and $i93
at December 31, 2022 and 2021, respectively, due to a tax sharing liability to TTI under a tax sharing agreement.
(3) The carrying value of our equity method investment is $i41 higher than the underlying equity in the net assets of the investee due to equity method goodwill.
(4) The
carrying value of our equity method investment is $i270 and $i276
higher than the underlying equity in the net assets of the investee at December 31, 2022 and 2021, 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.
(5)The carrying value of our equity method investment is $i5
higher than the underlying equity in the net assets of the investee due to guarantees.
(6) The carrying value of our equity method investment is $i130 higher than the underlying equity in the net assets of the investee due to equity method goodwill.
/
EARNINGS
(LOSSES) FROM EQUITY METHOD INVESTMENTS(1)
At
December 31, 2022 and 2021 our share of the undistributed earnings of equity method investments was $i2.0 billion and $i1.5
billion, respectively, including $i386 million at December 31, 2022 in undistributed earnings from investments for which we have less than 50% equity interests.
SEMPRA TEXAS UTILITIES
Oncor Holdings
We
account for our i100% ownership interest in Oncor Holdings, which owns an i80.25% interest in Oncor, as an equity method investment. Sempra does not
control Oncor Holdings or Oncor, and the ring-fencing measures, governance mechanisms and commitments in effect limit our ability to direct the management, policies and operations of Oncor Holdings and Oncor, including the deployment or disposition of their assets, declarations of dividends, strategic planning and other important corporate issues and actions. We also have limited representation on the Oncor Holdings and Oncor boards of directors.
Oncor is a domestic partnership for U.S. federal income tax purposes and is not included in the consolidated income tax return of Sempra. Rather, only our pretax equity earnings from our investment in Oncor Holdings (a disregarded entity for tax purposes) are included in our consolidated income tax return. A tax sharing agreement with TTI, Oncor Holdings and Oncor provides for the calculation of an income tax liability substantially as if Oncor Holdings and Oncor were taxed as corporations
and requires tax payments determined on that basis. While partnerships are not subject to income taxes, in consideration of the tax sharing agreement and Oncor being subject to the provisions of U.S. GAAP governing rate-regulated operations, Oncor recognizes amounts determined under cost-based regulatory rate-setting processes (with such costs including income taxes), as if it were taxed as a corporation. As a result, since Oncor Holdings consolidates Oncor, we recognize equity earnings from our investment in Oncor Holdings net of its recorded income tax.
In 2022, 2021 and 2020, Sempra contributed $i341
million, $i566 million and $i632 million, respectively, to Oncor Holdings.
(1) Excludes
adjustments to equity earnings related to amortization of a tax sharing liability associated with a tax sharing arrangement and changes in basis differences in AOCI within the carrying value of our equity method investment.
/
Sharyland Holdings
We account for our i50% ownership interest in Sharyland Holdings, a JV with SU Investment Partners,
L.P. that owns a i100% interest in Sharyland Utilities, as an equity method investment. In 2022, Sempra contributed $i5 million to Sharyland
Holdings.
SEMPRA INFRASTRUCTURE
Cameron LNG JV
Cameron LNG JV is a JV between Sempra and three project partners, TotalEnergies SE, Mitsui & Co., Ltd., and Japan LNG Investment, LLC, a company jointly owned by Mitsubishi Corporation and Nippon Yusen Kabushiki Kaisha. We account for our i50.2%
investment in Cameron LNG JV under the equity method.
In 2022, 2021 and 2020, Sempra Infrastructure contributed $i30 million, $i2
million and $i54 million, respectively, to Cameron LNG JV.
Sempra Promissory Note for SDSRA Distribution
Cameron LNG JV’s debt agreements require Cameron LNG JV to maintain the SDSRA, which is an additional reserve account beyond the Senior Debt Service Accrual Account, where funds accumulate from operations to satisfy senior debt
obligations due and payable on the next payment date. Both accounts can be funded with cash or authorized investments. In June 2021, Sempra Infrastructure received a distribution of $i165 million based on its proportionate share of the SDSRA, for which Sempra provided a promissory note and letters of credit to secure a proportionate share of Cameron LNG JV’s obligation to fund the SDSRA. Sempra’s maximum exposure to loss is replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA, or $i165
million. We recorded a guarantee liability of $i22 million in June 2021, with an associated carrying value of $i20 million at December 31, 2022, for
the fair value of the promissory note, which is being reduced over the duration of the guarantee through Sempra Infrastructure’s investment in Cameron LNG JV. The guarantee will terminate upon full repayment of Cameron LNG JV’s debt, scheduled to occur in 2039, or replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA.
Sempra Support Agreement for CFIN
In July 2020, CFIN entered into a financing arrangement with Cameron LNG JV’s four project owners and received aggregate proceeds of $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
paid from Cameron LNG JV’s project cash flows from its three-train natural gas liquefaction facility. Cameron LNG JV used the proceeds from its
loan to return equity to its project owners. Sempra used its $i753 million share of the proceeds for working capital and other general corporate purposes, including the repayment of indebtedness.
Sempra Infrastructure’s $i753
million proportionate share of the affiliate loans, based on SI Partners’ 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 has provided a guarantee pursuant to a Support Agreement under which:
▪Sempra has severally guaranteed repayment of the bank debt plus accrued and unpaid interest if CFIN fails to pay the
external lenders;
▪the external lenders may exercise an option to put the bank debt to Sempra Infrastructure upon the occurrence of certain events, including a failure by CFIN to meet its payment obligations under the bank debt;
▪the external lenders will put some or all of the bank debt to Sempra Infrastructure on the fifth, tenth, or fifteenth anniversary date of the affiliate loans, except the portion of the debt owed to any external lender that has elected not to participate in the put option six months prior to the respective anniversary date;
▪Sempra Infrastructure also has a right to call the bank debt back from, or to refinance the bank debt with, the external lenders at any time; and
▪the
Support Agreement will terminate upon full repayment of the bank debt, including repayment following an event in which the bank debt is put to Sempra Infrastructure.
In exchange for this guarantee, the external lenders will pay a guarantee fee that is based on the credit rating of Sempra’s long-term senior unsecured non-credit enhanced debt rating, which guarantee fee Sempra Infrastructure will recognize as interest income as earned. Sempra’s maximum exposure to loss is the bank debt plus any accrued and unpaid interest and related fees, subject to a liability cap of 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, 2022, the fair value of the Support Agreement was $i17
million, of which $i7 million is included in Other Current Assets and $i10 million is included in Other Long-Term Assets
on Sempra’s Consolidated Balance Sheet.
ESJ
As we discuss in Note 5, in March 2021, Sempra Infrastructure completed the acquisition of the remaining i50% equity interest in ESJ and ESJ became a consolidated subsidiary. Prior to the acquisition date, Sempra Infrastructure owned i50%
of ESJ and accounted for its interest as an equity method investment.
IMG
Sempra Infrastructure has a i40% interest in IMG, a JV with a subsidiary of TC Energy Corporation, and accounts for its interest as an equity method investment. IMG 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.
TAG
Sempra Infrastructure has a i50% beneficial ownership interest in TAG, a JV with TETL JV Mexico Norte, S. de R.L. de C.V. and Bravo N Mergeco, S. de R.L. de C.V. that holds a i50%
interest in the Los Ramones Norte pipeline. Sempra Infrastructure accounts for its i50% interest in TAG as an equity method investment.
PARENT AND OTHER
RBS Sempra Commodities
RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra and RBS in 2008 to own and operate the commodities-marketing businesses
previously operated through wholly owned subsidiaries of Sempra. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. Since 2011, our investment balance has reflected our share of the remaining partnership assets, including amounts retained by the partnership to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership and the distribution of the partnership’s remaining assets, if any. We account for our investment in RBS Sempra Commodities under the equity method.
In 2018, we fully impaired our remaining equity method investment in RBS Sempra Commodities. In 2020, we recorded a charge of $i100
million in Equity Earnings on Sempra’s Consolidated Statement of Operations for losses from our investment in RBS
Sempra Commodities. In 2021, we reduced this charge by $i50 million
based on the favorable outcome of a settlement with HMRC and revised assumptions on the High Court of Justice case. We discuss matters related to RBS Sempra Commodities further in “Other Litigation” in Note 16.
SUMMARIZED FINANCIAL INFORMATION
We present summarized financial information below, aggregated for all other equity method investments (excluding Oncor Holdings and RBS Sempra Commodities) for the periods in which we were invested in the entities. The amounts below represent the results of operations and aggregate financial position of 100% of each of Sempra’s other equity method investments.
SUMMARIZED
FINANCIAL INFORMATION – OTHER EQUITY METHOD INVESTMENTS
(1) In
March 2021, Sempra Infrastructure completed the acquisition of the remaining i50% equity interest in ESJ and ESJ became a consolidated subsidiary.
(2) Except for our investments in Mexico, there was no income tax recorded by the entities, as they are primarily domestic partnerships.
(3) Amounts for Cameron LNG JV exclude adjustments to equity earnings related to amortization of capitalized interest and
guarantee fees within the carrying value of our equity method investment and changes in basis differences in equity earnings related to AOCI.
NOTE 7. iDEBT
AND CREDIT FACILITIES
SHORT-TERM DEBT
Committed Lines of Credit
At December 31, 2022, Sempra had an aggregate capacity of $i9.7 billion under iseven
primary committed lines of credit, which provide liquidity and support our commercial paper programs. Because our commercial paper programs are supported by some of these lines of credit, we reflect the amount of commercial paper outstanding, before reductions of any unamortized discounts, and any letters of credit outstanding as a reduction to the available unused credit capacity in the following table.
The
principal terms of Sempra’s, SDG&E’s and SoCalGas’ lines of credit reflected in the table above include the following:
▪Each facility has a syndicate of i23 lenders. No single lender has greater than a i6%
share in any facility.
▪Sempra’s, SDG&E’s and SoCalGas’ facilities provide for the issuance of $i200 million, $i100
million and $i150 million, respectively, of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra, SDG&E and SoCalGas each has the right to increase its letter of credit commitment to up to $i500
million, $i250 million and $i250 million, respectively.
▪Borrowings bear interest at a benchmark
rate plus a margin that varies with the borrower’s credit rating.
▪Each borrower must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) of no more than i65% at the end of each quarter. At December 31, 2022, each entity was in compliance with this ratio under its respective credit facility.
The
principal terms of SI Partners’ line of credit reflected in the table above include the following:
▪A syndication of i12 lenders each having an i8.33%
share in the facility.
▪The facility provides for issuance of $i200 million of letters of credit.
▪The facility includes a $i100 million
swingline loan sub-limit, whereby any outstanding amounts would reduce available unused credit. No swingline loan borrowings were outstanding at December 31, 2022.
▪Borrowings are issued in U.S. dollars and letters of credit can be issued in U.S. dollars or Mexican pesos.
▪Borrowings bear interest at a benchmark rate plus a margin that varies with SI Partners’ credit rating.
▪SI Partners must maintain a ratio of consolidated adjusted net indebtedness to consolidated earnings before interest, taxes, depreciation and amortization (as defined in its credit facility) of no more than i5.25
to 1.00 as of the end of each quarter. At December 31, 2022, SI Partners was in compliance with this ratio.
The principal terms of the ithree lines of credit reflected in the table above that are shared by IEnova and SI Partners include the following:
▪The $i350
million revolving credit facility has a single lender and borrowings bear interest at a per annum rate equal to 3-month LIBOR plus i54 bps through December 29, 2022. On December 30, 2022, the facility was amended to replace the interest rate to Term SOFR plus i64
bps.
▪The $i150 million revolving credit facility has a single lender and borrowings bear interest at a per annum rate equal to Term SOFR plus i70
bps.
▪The $i1.5 billion revolving credit facility has a syndicate of i10 lenders
and borrowings bear interest at a per annum rate equal to 3-month LIBOR plus i80 bps through December 29, 2022. On December 30, 2022, the facility was amended to replace the interest rate to Term SOFR plus i90
bps.
▪Borrowings can be issued in U.S. dollars only.
Uncommitted Line of Credit
ECA LNG Phase 1 has an uncommitted line of credit, which is generally used for working capital requirements, with an aggregate capacity of $i200 million of which $i49
million was outstanding at December 31, 2022. The amount outstanding is before reductions of any unamortized discounts. The facility expires in August 2023 and borrowings can be in U.S. dollars or Mexican pesos. At December 31, 2022, outstanding amounts were borrowed in Mexican pesos and bear interest at a variable rate based on the 28-day Interbank Equilibrium Interest Rate plus i105 bps. Borrowings made in U.S. dollars bear interest at a variable rate based on the
1-month or 3-month LIBOR plus i105 bps.
Outside
of our domestic and foreign credit facilities, we have bilateral unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At December 31, 2022, we had $i594 million in standby letters of credit outstanding under these agreements.
In July 2022, SoCalGas entered into an $i800 million, i364-day term loan agreement with a maturity date of July 6, 2023. In August 2022, SoCalGas borrowed $i800
million, net of negligible debt issuance costs, under the term loan agreement. The borrowing bears interest at benchmark rates plus i70 bps and is due in full upon maturity. SoCalGas used the proceeds for payment of a portion of the costs relating to litigation pertaining to the Leak.
Weighted-Average Interest Rates
The weighted-average interest rates on all short-term debt were as follows:
(1) Callable
long-term debt not subject to make-whole provisions.
(2) Debt is not callable.
i
At December 31, 2022, scheduled maturities of long-term debt are as follows:
MATURITIES
OF LONG-TERM DEBT(1)
(Dollars in millions)
SDG&E
SoCalGas
Other Sempra
Total Sempra
2023
$
i450
$
i300
$
i212
$
i962
2024
i400
i500
i30
i930
2025
i—
i350
i1,374
i1,724
2026
i750
i504
i49
i1,303
2027
i—
i700
i799
i1,499
Thereafter
i6,200
i3,705
i8,190
i18,095
Total
$
i7,800
$
i6,059
$
i10,654
$
i24,513
/
(1) Excludes
finance lease obligations, discounts, and debt issuance costs.
Various long-term obligations totaling $i12.1 billion at Sempra at December 31, 2022 are unsecured. This includes unsecured long-term obligations totaling $i400
million at SDG&E and $i1.0 billion at SoCalGas.
At
the option of Sempra, SDG&E and SoCalGas, certain debt at December 31, 2022 is callable subject to premiums:
CALLABLE LONG-TERM DEBT
(Dollars in millions)
SDG&E
SoCalGas
Other Sempra
Total Sempra
Not
subject to make-whole provisions
$
i400
$
i304
$
i2,288
$
i2,992
Subject
to make-whole provisions
i7,400
i5,750
i8,366
i21,516
/
First
Mortgage Bonds
SDG&E and SoCalGas issue first mortgage bonds secured by liens on their respective utility plant assets. SDG&E and SoCalGas may issue additional first mortgage bonds if in compliance with the provisions of their bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of additional first mortgage bonds of $i7.8
billion at SDG&E and $i1.9 billion at SoCalGas at December 31, 2022.
SDG&E
In March 2022, SDG&E issued $i500
million aggregate principal amount of i3.00% first mortgage bonds due in full upon maturity on March 15, 2032 and received proceeds of $i494
million (net of debt discount, underwriting discounts and debt issuance costs of $i6 million), and $i500
million aggregate principal amount of i3.70% first mortgage bonds due in full upon maturity on March 15, 2052 and received proceeds of $i492 million (net of debt discount,
underwriting discounts and debt issuance costs of $i8 million). Each series of first mortgage bonds is redeemable prior to maturity, subject to its terms, and in certain circumstances subject to make-whole provisions. SDG&E used the net proceeds for repayment of commercial paper and its i364-day
term loan and for capital expenditures and other general corporate purposes.
SoCalGas
In November 2022, SoCalGas issued $i600 million aggregate principal amount of i6.35%
green first mortgage bonds due in full upon maturity on November 15, 2052 and received proceeds of $i592 million (net of debt discount, underwriting discounts and debt issuance costs of $i8
million). The first mortgage bonds are redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions. SoCalGas intends to use the net proceeds to finance or refinance eligible projects that fall into one or more of the following categories: pollution prevention and control, green buildings and clean transportation.
Other Long-Term Debt
Sempra
In March 2022, we issued $i750 million aggregate principal
amount of i3.30% senior unsecured notes due in full upon maturity on April 1, 2025 and received proceeds of $i745 million
(net of debt discount, underwriting discounts and debt issuance costs of $i5 million), and $i500 million
of i3.70% senior unsecured notes due in full upon maturity on April 1, 2029 and received proceeds of $i494 million (net
of debt discount, underwriting discounts and debt issuance costs of $i6 million). Each series of notes is redeemable prior to maturity, subject to its terms, and in certain circumstances subject to make-whole provisions. We used the net proceeds for general corporate purposes and repayment of commercial paper.
SDG&E
In February 2022, SDG&E entered into a $i400
million, itwo-year term loan with a maturity date of February 18, 2024. SDG&E borrowed $i200 million in the three months ended March 31, 2022 and
an additional $i200 million in the three months ended June 30, 2022. The borrowings bear interest at benchmark rates plus i62.5
bps and are due in full upon maturity. The margin is based on SDG&E’s long-term senior unsecured credit rating. SDG&E used the net proceeds for repayment of commercial paper and for general corporate purposes.
In March 2022, SoCalGas issued $i700
million aggregate principal amount of i2.95% senior unsecured notes due in full upon maturity on April 15, 2027 and received proceeds of $i691
million (net of debt discount, underwriting discounts and debt issuance costs of $i9 million). The notes are redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions. SoCalGas used the net proceeds for repayment of commercial paper and general corporate purposes.
Sempra Infrastructure
SI Partners. In January 2022, SI Partners
completed a private offering of $i400 million in aggregate principal of i3.25% senior unsecured notes due in full upon maturity on January
15, 2032 to “qualified institutional buyers” as defined in Rule 144A under the Securities Act of 1933, as amended (the Securities Act), and non-U.S. persons outside the U.S. under Regulation S under the Securities Act. The notes are redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions, and holders of the notes have the right to require SI Partners to offer to purchase some or all of the notes at a premium upon the occurrence of specific kinds of change of control events that result in a downgrade of SI Partners’ credit ratings. Sempra Infrastructure received proceeds of $i390
million (net of debt discount, underwriting discounts and debt issuance costs of $i10 million). Sempra Infrastructure used the net proceeds for general corporate purposes, including the repayment of certain indebtedness of its subsidiaries.
ECA LNG Phase 1. In December 2020, ECA LNG Phase 1 entered into a ifive-year
loan agreement with a syndicate of inine external lenders for an aggregate principal amount of up to $i1.5
billion. Sempra, IEnova and TotalEnergies SE 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. At issuance, borrowings under the loan agreement bore 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 interest rate at any time be less than i0% per annum. In July 2022, ECA LNG Phase 1 replaced Sempra with IEnova as the guarantor and replaced itwo
of the inine external lenders and their combined principal commitment of $i203 million (of which
$i64 million was outstanding and repaid) with a shareholder loan from IEnova, thereby reducing the syndicate to iseven
external lenders, increasing the weighted-average blended rate to i2.86% and reducing the aggregate principal amount of borrowing capacity from external lenders to $i1.3
billion. In December 2022, the loan agreement was amended to change the benchmark interest rate per annum to (a) the Term SOFR based on a tenor comparable to the applicable interest period, plus (b) a i0.10% margin per annum, for any interest period beginning on or after December 30, 2022. At December 31, 2022 and December 31, 2021, $i575
million and $i341 million, respectively, of borrowings from external lenders were outstanding under the loan agreement, with a weighted-average interest rate of i7.54% and i2.93%,
respectively.
IEnova Pipelines. In September 2022, Sempra Infrastructure used proceeds from borrowings against IEnova’s committed and uncommitted lines of credit to fully repay $i141 million of outstanding principal plus accrued and unpaid interest on the IEnova Pipelines variable-rate loans prior to scheduled maturity dates through 2026, and recognized approximately $i2
million ($i1 million after tax and NCI) in charges associated with the write-off of acquisition-related fair value adjustments offset by a hedge termination benefit.
Income
from continuing operations before income taxes and equity earnings
$
i1,343
$
i219
$
i1,489
Equity
earnings, before income tax(1)
i666
i614
i294
Pretax
income
$
i2,009
$
i833
$
i1,783
Effective
income tax rate
i28
%
i12
%
i14
%
SDG&E:
Income
tax expense
$
i182
$
i201
$
i190
Income
before income taxes
$
i1,097
$
i1,020
$
i1,014
Effective
income tax rate
i17
%
i20
%
i19
%
SoCalGas:
Income
tax expense (benefit)
$
i138
$
(i310)
$
i96
Income
(loss) before income taxes
$
i738
$
(i736)
$
i601
Effective
income tax rate
i19
%
i42
%
i16
%
(1)We
discuss how we recognize equity earnings in Note 6.
/
For SDG&E and SoCalGas, the CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the ETR. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations
in the ETR. The following items are subject to flow-through treatment:
▪repairs expenditures related to a certain portion of utility plant fixed assets
▪the equity portion of AFUDC, which is non-taxable
▪a portion of the cost of removal of utility plant assets
▪utility self-developed software expenditures
▪depreciation on a certain portion of utility plant assets
▪state income taxes
The AFUDC related to equity recorded for regulated construction projects at Sempra Infrastructure has
similar flow-through treatment.
Non-U.S.
earnings taxed at rates different from the U.S. statutory income tax rate(2)
i3
i5
i2
State
income taxes, net of federal income tax benefit
i1
(i4)
i1
Compensation-related
items
i—
(i1)
(i1)
Impairment
losses
i—
(i1)
i1
Noncontrolling
interests
i—
(i2)
i—
Utility
self-developed software expenditures
i—
(i5)
(i3)
Allowance
for equity funds used during construction
(i1)
(i3)
(i1)
Tax
credits
(i1)
i—
(i1)
Amortization
of excess deferred income taxes
(i2)
(i3)
(i1)
Resolution
of prior years’ income tax items
(i2)
i—
i—
Valuation
allowances
(i2)
i1
(i1)
Remeasurement
of deferred taxes
(i3)
(i4)
i—
Utility
repairs expenditures
(i5)
(i9)
(i4)
Other,
net
i—
(i1)
i1
Effective
income tax rate
i28
%
i12
%
i14
%
SDG&E:
U.S.
federal statutory income tax rate
i21
%
i21
%
i21
%
State
income taxes, net of federal income tax benefit
i4
i5
i5
Depreciation
i3
i3
i3
Self-developed
software expenditures
i—
(i1)
(i4)
Amortization
of excess deferred income taxes
(i2)
(i2)
(i1)
Allowance
for equity funds used during construction
(i2)
(i2)
(i2)
Resolution
of prior years’ income tax items
(i2)
i—
i—
Repairs
expenditures
(i5)
(i4)
(i3)
Effective
income tax rate
i17
%
i20
%
i19
%
SoCalGas:
U.S.
federal statutory income tax rate
i21
%
i21
%
i21
%
Depreciation
i5
(i5)
i5
State
income taxes, net of federal income tax benefit
i2
i11
i2
Nondeductible
expenditures
i2
i—
i2
Self-developed
software expenditures
i—
i5
(i4)
Amortization
of excess deferred income taxes
(i2)
i2
(i1)
Allowance
for equity funds used during construction
(i2)
i1
(i1)
Repairs
expenditures
(i6)
i5
(i7)
Other,
net
(i1)
i2
(i1)
Effective
income tax rate
i19
%
i42
%
i16
%
(1)Due
to fluctuation of the Mexican peso against the U.S. dollar. We record income tax expense (benefit) from the transactional effects of foreign currency and inflation because of appreciation (depreciation) of the Mexican peso. In 2021 and 2020, we also recognized gains (losses) in Other Income (Expense), Net, on the Consolidated Statements of Operations from foreign currency derivatives that were partially hedging Sempra Infrastructure’s exposure to movements in the Mexican peso from its controlling interest in IEnova.
(2)Related to operations in Mexico.
We expect to repatriate approximately $i2.1
billion of foreign undistributed earnings in the foreseeable future, and have accrued $i65 million of U.S. state deferred income tax liability at December 31, 2022. We repatriated approximately $i38
million to the U.S. in 2021.
In the year ended December 31, 2022, we recognized income tax expense of $i120 million
for a deferred income tax liability related to outside basis differences in our foreign subsidiaries that we had previously considered to be indefinitely reinvested. We have not recorded deferred income taxes with respect to remaining basis differences of approximately $i600 million between financial statement and income tax investment amounts in our non-U.S. subsidiaries because we consider them to be indefinitely reinvested as of December 31, 2022. 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.
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 2021 compared to 2022 and 2020 primarily due to the 2021 charges at SoCalGas related to civil litigation pertaining to the Leak, which we describe in Note 16.
Differences in financial
and tax bases of fixed assets, investments and other assets(1)
$
i5,533
$
i5,230
U.S.
state and non-U.S. withholding tax on repatriation of foreign earnings
i53
i47
Regulatory
balancing accounts
i632
i538
Right-of-use
assets – operating leases
i177
i160
Property
taxes
i60
i52
Postretirement
benefits
i31
i—
Other
deferred income tax liabilities
i55
i50
Total
deferred income tax liabilities
i6,541
i6,077
Deferred
income tax assets:
Tax credits
i1,210
i1,135
Net
operating losses
i579
i706
Postretirement
benefits
i—
i30
Compensation-related
items
i144
i164
Operating
lease liabilities
i164
i140
Other
deferred income tax assets
i40
i130
State
income taxes
i—
i21
Bad
debt allowance
i48
i33
Accrued
expenses not yet deductible
i92
i575
Deferred
income tax assets before valuation allowances
i2,277
i2,934
Less:
valuation allowances
i192
i183
Total
deferred income tax assets
i2,085
i2,751
Net
deferred income tax liability(2)
$
i4,456
$
i3,326
(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, 2022 and 2021, includes $i135 and $i151,
respectively, recorded as a noncurrent asset and $i4,591 and $i3,477, 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” table.
Potential
resolution of audit issues with various U.S. federal, state and local and non-U.S. taxing authorities
$
i8
$
i8
$
i8
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 (Benefit) on the Consolidated Statements of Operations. Sempra, SDG&E and SoCalGas each accrued negligible amounts for interest expense and penalties at December 31, 2022 and 2021 on the Consolidated Balance Sheets, and recorded negligible amounts for interest expense and penalties on the Consolidated Statements of Operations for all periods presented.
INCOME TAX AUDITS
Sempra is subject to U.S. federal income tax as well as income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2018. 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.
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 2018 and state tax years after 2012.
In addition, Sempra has filed protests to contest proposed state audit adjustments for tax years 2009 through 2012. The pre-2013 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years.
NOTE
9. 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 and its consolidated entities.
Sempra has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees. Pension benefits under the traditional defined benefit plans are based on service and final average earnings, while the cash balance plans provide benefits using a career average earnings methodology.
IEnova
has an unfunded noncontributory defined benefit plan covering all employees that provides defined benefits to retirees based on date of hire, years of service and final average earnings.
Sempra also has PBOP plans, including separate plans for SDG&E and SoCalGas, which collectively cover all domestic and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. PBOP plans include medical benefits.
Pension
and PBOP 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.
DEDICATED ASSETS IN SUPPORT OF CERTAIN BENEFITS PLANS
In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $i505
million and $i567 million at December 31, 2022 and 2021, respectively.
PENSION AND PBOP PLANS
Oncor
In 2022 and 2021, we had $i26 million
and $i7 million, respectively, in AOCI representing an actuarial loss related to Oncor’s pension plans.
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 2022 and 2021, and a statement of the funded status at December 31, 2022 and 2021.
PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars
in millions)
Pension(1)
PBOP
2022
2021
2022
2021
Sempra:
CHANGE
IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1
$
i3,857
$
i4,077
$
i940
$
i989
Service
cost
i146
i145
i23
i23
Interest
cost
i118
i112
i28
i28
Contributions
from plan participants
i—
i—
i23
i21
Actuarial
gain
(i925)
(i76)
(i282)
(i53)
Benefit
payments
(i89)
(i98)
(i69)
(i68)
Settlements
(i301)
(i303)
i—
i—
Net
obligation at December 31
i2,806
i3,857
i663
i940
CHANGE
IN PLAN ASSETS
Fair value of plan assets at January 1
i3,182
i3,002
i1,408
i1,399
Actual
return on plan assets
(i625)
i340
(i271)
i51
Employer
contributions
i223
i241
i5
i5
Contributions
from plan participants
i—
i—
i23
i21
Benefit
payments
(i89)
(i98)
(i69)
(i68)
Settlements
(i301)
(i303)
i—
i—
Fair
value of plan assets at December 31
i2,390
i3,182
i1,096
i1,408
Funded
status at December 31
$
(i416)
$
(i675)
$
i433
$
i468
Net
recorded (liability) asset at December 31
$
(i416)
$
(i675)
$
i433
$
i468
(1) The
accumulated benefit obligation was $i2,574 and $i3,419 at December 31,
2022 and 2021, respectively.
PROJECTED
BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
Pension(1)
PBOP
2022
2021
2022
2021
SDG&E:
CHANGE
IN PROJECTED BENEFIT OBLIGATION
Net obligation at January 1
$
i885
$
i913
$
i188
$
i193
Service
cost
i37
i35
i5
i5
Interest
cost
i26
i25
i6
i5
Contributions
from plan participants
i—
i—
i8
i7
Actuarial
gain
(i135)
(i2)
(i54)
(i3)
Benefit
payments
(i17)
(i17)
(i19)
(i19)
Settlements
(i82)
(i69)
i—
i—
Net
obligation at December 31
i714
i885
i134
i188
CHANGE
IN PLAN ASSETS
Fair value of plan assets at January 1
i859
i819
i197
i213
Actual
return on plan assets
(i142)
i73
(i40)
(i5)
Employer
contributions
i52
i53
i1
i1
Contributions
from plan participants
i—
i—
i8
i7
Benefit
payments
(i17)
(i17)
(i19)
(i19)
Settlements
(i82)
(i69)
i—
i—
Fair
value of plan assets at December 31
i670
i859
i147
i197
Funded
status at December 31
$
(i44)
$
(i26)
$
i13
$
i9
Net
recorded (liability) asset at December 31
$
(i44)
$
(i26)
$
i13
$
i9
(1) The
accumulated benefit obligation was $i678 and $i824 at December 31, 2022 and 2021,
respectively.
PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
Pension(1)
PBOP
(Dollars
in millions)
2022
2021
2022
2021
SoCalGas:
CHANGE IN PROJECTED BENEFIT OBLIGATION
Net
obligation at January 1
$
i2,647
$
i2,829
$
i706
$
i749
Service
cost
i96
i97
i17
i17
Interest
cost
i81
i78
i21
i22
Contributions
from plan participants
i—
i—
i14
i13
Actuarial
gain
(i748)
(i83)
(i215)
(i49)
Benefit
payments
(i58)
(i63)
(i46)
(i46)
Settlements
(i204)
(i211)
i—
i—
Net
obligation at December 31
i1,814
i2,647
i497
i706
CHANGE
IN PLAN ASSETS
Fair value of plan assets at January 1
i2,095
i1,969
i1,178
i1,159
Actual
return on plan assets
(i449)
i243
(i224)
i51
Employer
contributions
i151
i157
i1
i1
Contributions
from plan participants
i—
i—
i14
i13
Benefit
payments
(i58)
(i63)
(i46)
(i46)
Settlements
(i204)
(i211)
i—
i—
Fair
value of plan assets at December 31
i1,535
i2,095
i923
i1,178
Funded
status at December 31
$
(i279)
$
(i552)
$
i426
$
i472
Net
recorded (liability) asset at December 31
$
(i279)
$
(i552)
$
i426
$
i472
(1) The
accumulated benefit obligation was $i1,644 and $i2,306 at December 31,
2022 and 2021, respectively.
Actuarial (gains) losses fluctuate based on changes in assumptions that we describe below in “Assumptions for Pension and PBOP Plans” and updates to census data. In 2021, the Society of Actuaries released updated mortality improvement projection scales, reflecting changes to projected observed longevity improvements in its mortality tables. There was no update in 2022. We
have
incorporated these assumptions, adjusted for the Sempra companies’ actual mortality experience, in our calculations for each of those years.
▪Actuarial gains in pension plans at Sempra in 2022 were driven primarily by an increase in discount rates at SoCalGas, SDG&E and Sempra, a change in the rates used to convert traditional pension benefits to lump-sums at SoCalGas, and administrative changes in the long-term disability plan at SoCalGas. These actuarial gains were partially offset by actuarial losses due to an increase in the interest crediting rate for the cash balance plans at SDG&E, SoCalGas and Sempra, changes in the rates used to convert cash balance accounts to traditional pension benefit distributions at SDG&E, and updated census data at SoCalGas and Sempra.
▪Actuarial gains in PBOP plans at Sempra
in 2022 were driven primarily by an increase in discount rates at SoCalGas, SDG&E and Sempra.
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 PBOP costs over a period of years. Our funded pension and PBOP plans use the asset smoothing method, except for those at SDG&E. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic benefit cost. SDG&E does not use the
asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year.
The 10% corridor accounting method is used at Sempra, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants (or, for plans where participants are substantially inactive employees, the average remaining lifetime of all participants or the period for which benefits will be paid, whichever is shorter). The asset smoothing and 10% corridor accounting methods help mitigate volatility of net periodic benefit costs from year to year.
Defined benefit pension and PBOP plans with an aggregated overfunded status
are recognized as an asset and with an aggregated underfunded status are recognized as a liability; unrecognized changes in these assets and/or liabilities are normally recorded in AOCI on the balance sheet. SDG&E and SoCalGas record regulatory assets and liabilities that offset the funded pension and PBOP plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on decisions by regulatory agencies.
SDG&E and SoCalGas record annual pension and PBOP 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 benefit 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 PBOP plans for SDG&E and SoCalGas are disclosed as regulatory adjustments in accordance with U.S. GAAP for rate-regulated entities.
Sempra, 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.
Sempra,
SDG&E and SoCalGas each have a funded PBOP plan. The following table shows the obligations of funded PBOP plans with accumulated postretirement benefit obligations in excess of plan assets.
CHANGES
IN PLAN ASSETS AND BENEFIT OBLIGATIONS RECOGNIZED IN OCI
Net (gain) loss
(i5)
i2
i6
Transfer
of actuarial loss
i—
i—
i5
Transfer
of prior service cost
i—
i—
i3
Amortization
of actuarial loss
(i2)
(i1)
(i1)
Amortization
of prior service cost
(i1)
(i1)
(i1)
Total
recognized in OCI
(i8)
i—
i12
Total
recognized in net periodic benefit cost and OCI
$
i147
$
i154
$
i166
Assumptions
for Pension and PBOP 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.
Assumed
health care cost trend rates have a significant effect on the amounts that Sempra, SDG&E and SoCalGas report for the health care plan costs. Following are the health care cost trend rates applicable to our PBOP plans:
Rate
to which the cost trend rate is assumed to decline (the ultimate trend)
iii4.75//
%
iii4.75//
%
iii4.75//
%
iii4.50//
%
iii4.50//
%
iii4.50//
%
Year
the rate reaches the ultimate trend
2028
2025
2025
2022
2022
2022
/i
Plan
Assets
Investment Allocation Strategy for Sempra’s Pension Master Trust
Sempra’s pension master trust holds the investments for our pension plans and a portion of the investments for our PBOP plans. We maintain additional trusts, as we discuss below, for certain of SDGE’s and SoCalGas’ PBOP plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra.
The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. A portion of the pension master trust is invested in accordance with plan specific de-risking glidepaths designed to reduce the assets’ exposure to risk as the plans become better funded. We assess the portfolio performance by comparing actual returns with
relevant benchmarks. iThe target asset allocations for Sempra’s pension master trust are between return-seeking assets (i.e., generally, equity securities, high-yield fixed income securities and other instruments with a similar risk profile) and risk-mitigating assets (i.e., generally, government and corporate fixed income securities) as follows:
TARGET
ASSET ALLOCATIONS FOR SEMPRA’S PENSION MASTER TRUST
(Dollars in millions)
Sempra
SDG&E
SoCalGas
Return-seeking assets
i34
%
i42
%
i65
%
Risk-mitigating
assets
i66
%
i58
%
i35
%
We
maintain asset allocations at strategic levels within reasonable bands of variance. The asset allocations are reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis to help ensure that plan assets are positioned to meet plan obligations. 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
In accordance with the Sempra pension investment guidelines, derivative financial instruments may be
used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.
Rate of Return Assumption
The expected return on assets in our pension and PBOP plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date. We 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 SDG&E’s and SoCalGas’ PBOP plans are subject to taxation, which impacts the expected after-tax return on assets in the plan.
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 Sempra’s, SDG&E’s and SoCalGas’ PBOP Plans
Sempra’s PBOP plan is funded by cash contributions from Sempra. 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 and are invested in accordance with a de-risking glidepath designed to reduce
the assets’ exposure to risk as the trusts become better funded. These specific allocations are periodically reviewed to help ensure that plan assets are positioned to meet plan obligations. The target asset allocations for the PBOP plans are between return-seeking assets and risk-mitigating assets as follows:
TARGET ASSET ALLOCATIONS FOR PBOP PLANS
(Dollars in millions)
Sempra
SDG&E
and SoCalGas
Assets held in pension master trust
Assets held in pension master trust
Assets held in Voluntary Employee Beneficiary Association trusts
Return-seeking assets
i74
%
i38
%
i30
%
Risk-mitigating
assets
i26
%
i62
%
i70
%
Fair
Value of Pension and PBOP Plan Assets
We classify the investments in Sempra’s pension master trust and the trusts for SDG&E’s and SoCalGas’ PBOP plans based on the fair value hierarchy, except for certain investments measured at NAV.
The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and PBOP plan trusts.
Equity Securities – Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.
Registered Investment Companies – Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices. Where the value is a quoted price in an active market, the investment is classified
within Level 1 of the fair value hierarchy. Other investments are valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.
Fixed Income Securities – Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flow approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.
Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.
Common/Collective Trusts – Investments in common/collective trust funds are valued based on the NAV of units owned, which is based on the current fair value of the funds’ underlying assets.
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 PBOP plan trusts measured at fair value on a recurring basis.
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 PBOP PLANS
We expect to contribute the following amounts to our pension and PBOP plans in 2023:
EXPECTED
CONTRIBUTIONS
(Dollars in millions)
Sempra
SDG&E
SoCalGas
Pension plans
$
i233
$
i53
$
i153
PBOP
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
SDG&E
SoCalGas
Pension
PBOP
Pension
PBOP
Pension
PBOP
2023
$
i223
$
i46
$
i58
$
i10
$
i130
$
i33
2024
i220
i45
i58
i10
i129
i33
2025
i216
i45
i59
i10
i131
i32
2026
i220
i47
i57
i10
i132
i32
2027
i220
i44
i56
i10
i129
i32
2028-2032
i1,062
i220
i285
i47
i654
i161
/
SAVINGS
PLANS
Sempra, SDG&E and SoCalGas offer trusteed savings plans to all employees. Employee participation, employee contributions and employer matching contributions are subject to the provisions of the respective plans, and for employee contributions, limits imposed by the respective governmental authorities.
i
Employer contributions to the savings plans were as follows:
Sempra has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra. The plans permit a wide variety of share-based awards, including:
▪nonqualified stock options
▪incentive
stock options
▪restricted stock awards
▪restricted stock units
▪stock appreciation rights
▪performance awards
▪stock payments
▪dividend equivalents
Eligible employees, including those from SDG&E and SoCalGas, participate in Sempra’s share-based compensation plans as a component of their compensation package.
In the three years ended December 31, 2022, Sempra had the following types of
equity awards outstanding:
▪Nonqualified Stock Options: Options to purchase common stock have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a three-year period and expire i10 years from the date of grant. Unvested option awards are subject to forfeiture following a termination of employment, except where the retirement criteria under
such awards have been met and subject to certain other exceptions described below.
▪Performance-Based Restricted Stock Units: These RSU awards generally vest in Sempra common stock at the end of three-year performance periods based on Sempra’s total return to shareholders relative to that of specified market indices or based on the compound annual growth rate of Sempra’s EPS. The comparative market indices for the awards that vest based on total return to shareholders are the S&P 500 Utilities Index (excluding water companies) and the S&P 500 Index. We use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies (excluding water companies) to develop our targets for awards that vest based on EPS growth. These RSU awards are subject to forfeiture prior to vesting following a termination of employment, except
where the retirement criteria under such awards have been met and subject to certain other exceptions described below.
◦If Sempra’s total return to shareholders or EPS growth is below the target levels but above threshold performance levels, shares are subject to partial vesting on a pro rata basis. If Sempra’s total return to shareholders or EPS growth exceeds target levels, up to an additional i100%
of the granted RSUs may be issued.
◦For certain awards granted in 2018 that vest based on Sempra’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 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.
▪Service-Based Restricted Stock Units: RSUs may also be service-based; these generally vest ratably over three-year service periods (for awards granted after 2018), or at the end of three-year service periods (for awards granted during 2018). These awards are subject to earlier forfeiture upon termination of employment, subject to certain exceptions described below.
For awards that would otherwise be forfeited upon termination of employment, the Compensation and Talent Development Committee of Sempra’s board of directors may waive the forfeiture requirement
and, with respect to options and service-based RSUs, may accelerate vesting. Awards are also subject to accelerated vesting under certain circumstances upon a change in control under the applicable LTIP, in accordance with severance pay agreements or to the extent otherwise required by the terms of the applicable award. Dividend equivalents on shares subject to RSUs are reinvested to purchase additional common shares that become subject to the same vesting conditions as the RSUs to which the dividends relate.
At December 31, 2022, ii5,056,550/ 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 years. However, for awards granted to retirement-eligible participants, the expense is recognized over the initial year in which the award was granted as the award requires service through the end of the year in which it was granted. For awards granted to participants who become eligible for retirement during the requisite service period, the expense is recognized over the period between the date of grant and the later of the end of the year in which the award was granted or the date the participant first becomes eligible for retirement. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards. We recognize in earnings the tax benefits (or deficiencies) resulting from tax deductions that are
in excess of (or less than) tax benefits related to compensation cost recognized for share-based payments.
Sempra subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra plans’ corporate staff costs. iTotal share-based compensation expense for all of Sempra’s share-based awards was comprised as follows:
Share-based compensation expense, before income taxes(1)
$
i61
$
i58
$
i62
Income
tax benefit(1)
(i17)
(i16)
(i17)
$
i44
$
i42
$
i45
Capitalized
share-based compensation cost
$
i11
$
i9
$
i11
Excess
income tax (benefit) deficiency
$
(i3)
$
(i9)
$
(i19)
SDG&E:
Share-based
compensation expense, before income taxes
$
i11
$
i10
$
i11
Income
tax benefit
(i3)
(i3)
(i3)
$
i8
$
i7
$
i8
Capitalized
share-based compensation cost
$
i6
$
i5
$
i7
Excess
income tax (benefit) deficiency
$
i—
$
(i1)
$
(i3)
SoCalGas:
Share-based
compensation expense, before income taxes
$
i17
$
i14
$
i14
Income
tax benefit
(i5)
(i4)
(i4)
$
i12
$
i10
$
i10
Capitalized
share-based compensation cost
$
i5
$
i4
$
i4
Excess
income tax (benefit) deficiency
$
i—
$
(i1)
$
(i3)
(1) Includes
activity of awards issued from the IEnova 2013 LTIP, which settled in cash upon vesting based on the price of IEnova’s common stock.
SEMPRA NONQUALIFIED STOCK OPTIONS
We use a Black-Scholes option-pricing model to estimate the fair value of each nonqualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on a blend of the historical and implied volatility of Sempra’s common stock price. The average expected term for options is based on the vesting schedule, contractual term of the option, expected employee exercise and post-termination behavior. The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected term estimated at the date of the grant. In 2022, 2021 and 2020, Sempra’s board of directors granted i219,898,
i222,620 and i154,860
nonqualified stock options, respectively, that become exercisable over a ithree-year period. The weighted-average per-share fair value for options
granted
was $i21.98, $i19.07
and $i19.76 in 2022, 2021 and 2020, respectively. iTo
calculate this fair value, we used the Black-Scholes model with the following weighted-average assumptions:
The
aggregate intrinsic value at December 31, 2022 is the total of the difference between Sempra’s closing common stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for nonqualified stock options exercised in the last three years was:
▪$i1.7
million in 2022
▪$i1.4 million in 2021
▪$i0.4
million in 2020
All compensation cost related to stock options had been recognized as of December 31, 2022. The weighted-average exercise price for nonqualified stock options granted in 2021 and 2020 was $i123.80 and $i149.12,
respectively.
We received cash of $i4 million, $i5 million and a negligible amount from
stock option exercises in 2022, 2021 and 2020, respectively.
SEMPRA RESTRICTED STOCK UNITS
We use Sempra’s common stock price at the grant date to estimate the fair value of our service-based RSUs and our RSUs that vest based on the compound annual growth rate of Sempra’s EPS.
We use a Monte-Carlo simulation model to estimate the fair value of our RSUs that vest based on Sempra’s total return to shareholders. Our determination of fair value is affected by the historical volatility of the common stock price for Sempra and its peer group companies. The valuation also is affected by the risk-free rates of return and a number of other variables. 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 exceeds target performance conditions.
/
In
2022, 2021 and 2020, the total fair value of RSU shares vested during the year was $i54 million, $i57
million and $i70 million, respectively.
We expect $i43
million of total compensation cost related to nonvested RSUs not yet recognized as of December 31, 2022 to be recognized over a weighted-average period of i1.6 years. The weighted-average per-share fair values for performance-based RSUs granted were $i133.03
and $i155.62 in 2021 and 2020, respectively. The weighted-average per-share fair values for service-based RSUs granted were $i124.84
and $i138.91 in 2021 and 2020, respectively.
NOTE
11. iDERIVATIVE FINANCIAL INSTRUMENTS
We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could
lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that could cause our asset values to fall or our liabilities to increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.
In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.
In all other cases, we record derivatives at fair value on the Consolidated Balance Sheets. We may have derivatives that are (1) cash flow hedges, (2) fair value hedges, or (3) undesignated. Depending on the applicability of hedge accounting and, for SDG&E and SoCalGas
and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in OCI (cash flow hedges), on the balance sheet (regulatory offsets), or recognized in earnings (fair value hedges and undesignated derivatives not subject to rate recovery). We classify cash flows from the principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt and hedge
termination
costs on interest rate swaps as financing activities and settlements of other derivative instruments as operating activities on the Consolidated Statements of Cash Flows.
i
HEDGE ACCOUNTING
We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating
cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria.
ENERGY DERIVATIVES
Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:
▪SDG&E and SoCalGas use natural gas derivatives and SDG&E uses electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risk,
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 limited by company policy. SDGE’s risk management and transacting activity plans for electricity derivatives are also required to be filed with, and have been approved by, the CPUC. SoCalGas is also subject to certain regulatory requirements and thresholds related to natural gas procurement under the GCIM. 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 Natural Gas or in Cost of Electric Fuel and Purchased
Power.
▪SDG&E is allocated and may purchase CRRs, which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations.
▪Sempra Infrastructure may use natural gas and electricity derivatives, as appropriate, in an effort to optimize the earnings of its assets which support the following businesses: LNG, natural gas pipelines and storage, and power generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues on the
Consolidated Statements of Operations.
▪From time to time, our various businesses, including SDG&E and SoCalGas, may use other energy derivatives to hedge exposures such as GHG allowances.
i
The following table summarizes net energy derivative volumes.
We are exposed to interest rates primarily as a result of our current and expected use of financing. SDG&E and SoCalGas, as well as Sempra and its other subsidiaries and JVs, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.
In
December 2022, Sempra Infrastructure entered into an undesignated contingent interest rate swap to lock in interest rates on up to $i3.5 billion of the variable rate indebtedness from anticipated future project-level debt financing that would be used to pay for construction costs of the proposed PA LNG Phase 1 project. The contingent interest rate swap has a i25-year
tenor, and its settlement is conditional upon the closing of project-level debt financing with respect to the proposed PA LNG Phase 1 project. We may elect to (i) cash settle the contingent interest rate swap five days after reaching the closing of project-level debt financing, or (ii) terminate the contingent interest rate swap and enter into new long-term interest rate swaps that are adjusted for the termination value of the contingent interest rate swap. We expect to close the project-level debt financing in the first quarter of 2023.
i
The
following table presents the net notional amounts of our interest rate derivatives, excluding those in our equity method investments and the contingent interest rate swap.
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 fixed interest rates for U.S. fixed interest rates. From time to time, Sempra Infrastructure and its JVs may use other foreign currency derivatives to hedge exposures related to cash flows associated with revenues from contracts denominated in Mexican pesos that are indexed to the U.S. dollar.
We are also exposed to exchange rate movements at our Mexican subsidiaries and JVs, which have U.S. dollar-denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income
tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We may utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts; however, we generally do not hedge our deferred income tax assets and liabilities or for inflation.
We also utilized foreign currency derivatives in 2020 to hedge exposure to fluctuations in the Peruvian sol and Chilean peso related to the sales of our operations in Peru and Chile, respectively.
The following table presents the net notional amounts of our foreign currency derivatives, excluding those in our equity
method investments.
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.
i
DERIVATIVE
INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
The
following table includes the effects of derivative instruments designated as cash flow hedges on the Consolidated Statements of Operations and in OCI and AOCI.
CASH
FLOW HEDGE IMPACTS
(Dollars in millions)
Pretax gain (loss) recognized in OCI
Pretax (loss) gain reclassified from AOCI into earnings
(1) Equity
earnings at our foreign equity method investees are recognized after tax.
/
For Sempra, we expect that net gains before NCI of $i31 million, which are net of income tax expense, that are currently recorded in AOCI (with
net gains of $i18 million attributable to NCI) related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. SoCalGas expects that $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, 2022 is approximately i12
years for Sempra. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is i17 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 (loss) gain on derivatives recognized
in earnings
For Sempra, SDG&E and SoCalGas, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.
For
Sempra, the total fair value of this group of derivative instruments in a liability position at December 31, 2022 and 2021 was $i106 million and $i88
million, respectively. For SoCalGas, the total fair value of this group of derivative instruments in a liability position at December 31, 2022 and 2021 was $i69 million and $i36
million, respectively. SDG&E did not have this group of derivative instruments in a liability position at December 31, 2022 or 2021. At December 31, 2022, if the credit ratings of Sempra or SoCalGas were reduced below investment grade, $i106 million and $i69
million, respectively, of additional assets could be required to be posted as collateral for these derivative contracts.
For Sempra, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.
NOTE
12. 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, 2022 and 2021. 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:
▪Nuclear
decommissioning trusts reflect the assets of SDG&E’s NDT, excluding accounts receivable and accounts payable. A third-party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).
▪For commodity contracts, interest rate instruments and foreign exchange instruments, we primarily use a market or income approach with market participant assumptions to value these derivatives. Market participant assumptions include those about
risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below in “Level 3 Information – SDG&E.”
▪Rabbi Trust investments include short-term investments that consist of money market and mutual funds that we value using a market approach based on closing
prices reported in the active market in which the identical security is traded (Level 1).
▪As we discuss in Note 6, in July 2020, Sempra entered into a Support Agreement for the benefit of CFIN. We measure the Support Agreement, which includes a guarantee obligation, a put option and a call option, net of related guarantee fees, at fair value on a recurring basis. We use a discounted cash flow model to value the Support Agreement, net of related guarantee fees.
Because
some of the inputs that are significant to the valuation are less observable, the Support Agreement is classified as Level 3, as we describe below in “Level 3 Information – Sempra Infrastructure.”
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies
i27
i13
i—
i40
Municipal
bonds
i—
i270
i—
i270
Other
securities
i—
i227
i—
i227
Total
debt securities
i27
i510
i—
i537
Total
nuclear decommissioning trusts(1)
i330
i515
i—
i845
Short-term
investments held in Rabbi Trust
i55
i—
i—
i55
Interest
rate instruments
i—
i76
i—
i76
Commodity
contracts not subject to rate recovery
i—
i273
i—
i273
Effect
of netting and allocation of collateral(2)
i451
i—
i—
i451
Commodity
contracts subject to rate recovery
i82
i19
i35
i136
Effect
of netting and allocation of collateral(2)
i12
i—
i6
i18
Support
Agreement, net of related guarantee fees
i—
i—
i17
i17
Total
$
i930
$
i883
$
i58
$
i1,871
Liabilities:
Foreign
exchange instruments
$
i—
$
i8
$
i—
$
i8
Interest
rate and foreign exchange instruments
i—
i105
i—
i105
Commodity
contracts not subject to rate recovery
i—
i191
i—
i191
Commodity
contracts subject to rate recovery
i—
i70
i—
i70
Total
$
i—
$
i374
$
i—
$
i374
(1) Excludes
receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies
i48
i8
i—
i56
Municipal
bonds
i—
i321
i—
i321
Other
securities
i—
i260
i—
i260
Total
debt securities
i48
i589
i—
i637
Total
nuclear decommissioning trusts(1)
i419
i585
i—
i1,004
Short-term
investments held in Rabbi Trust
i81
i—
i—
i81
Interest
rate instruments
i—
i6
i—
i6
Foreign
exchange instruments
i—
i2
i—
i2
Commodity
contracts not subject to rate recovery
i—
i46
i—
i46
Effect
of netting and allocation of collateral(2)
i58
i—
i—
i58
Commodity
contracts subject to rate recovery
i12
i1
i69
i82
Effect
of netting and allocation of collateral(2)
i31
i9
i6
i46
Support
Agreement, net of related guarantee fees
i—
i—
i7
i7
Total
$
i601
$
i649
$
i82
$
i1,332
Liabilities:
Interest
rate instruments
$
i—
$
i8
$
i—
$
i8
Foreign
exchange instruments
i—
i1
i—
i1
Interest
rate and foreign exchange instruments
i—
i131
i—
i131
Commodity
contracts not subject to rate recovery
i—
i31
i—
i31
Commodity
contracts subject to rate recovery
i—
i35
i15
i50
Total
$
i—
$
i206
$
i15
$
i221
(1) Excludes
receivables (payables), net.
(2) Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies
i48
i8
i—
i56
Municipal
bonds
i—
i321
i—
i321
Other
securities
i—
i260
i—
i260
Total
debt securities
i48
i589
i—
i637
Total
nuclear decommissioning trusts(1)
i419
i585
i—
i1,004
Commodity
contracts subject to rate recovery
i12
i—
i69
i81
Effect
of netting and allocation of collateral(2)
i22
i—
i6
i28
Total
$
i453
$
i585
$
i75
$
i1,113
Liabilities:
Commodity
contracts subject to rate recovery
$
i—
$
i—
$
i15
$
i15
Total
$
i—
$
i—
$
i15
$
i15
(1) Excludes
receivables (payables), net.
(2)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(1) Includes
the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Level 3 Information
SDG&E
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 and SDG&E.
LEVEL 3 RECONCILIATIONS(1)
(Dollars in millions)
2022
2021
2020
Balance
at January 1
$
i54
$
i69
$
i28
Realized
and unrealized (losses) gains
(i56)
(i50)
i19
Allocated
transmission instruments
(i4)
i3
i6
Settlements
i41
i32
i16
Balance
at December 31
$
i35
$
i54
$
i69
iChange
in unrealized (losses) gains relating to instruments still held at December 31
$
(i10)
$
(i16)
$
i34
(1)
Excludes the effect of the contractual ability to settle contracts under master netting agreements.
/
Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.
CRRs are recorded at fair value based almost entirely on
the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. 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:
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 significantly higher (lower) fair value measurement. We summarize CRR volumes in Note 11.
Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. The range and weighted-average price of these inputs at December 31 were as follows:
A
significant increase (decrease) in market electricity forward prices would result in a significantly higher (lower) fair value. We summarize long-term, fixed-price electricity position volumes in Note 11.
Realized gains and losses associated with CRRs and long-term, fixed-price electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Because unrealized gains and losses are recorded as regulatory assets and liabilities, they do not affect earnings.
Sempra Infrastructure
The table below sets forth reconciliations of changes in the fair value of Sempra’s Support Agreement for the benefit of CFIN classified as Level 3 in
the fair value hierarchy for Sempra.
LEVEL 3 RECONCILIATIONS
(Dollars in millions)
2022
2021
2020
Balance
at January 1
$
i7
$
i3
$
i—
Realized
and unrealized gains(1)
i19
i11
i6
Settlements
(i9)
(i7)
(i3)
Balance
at December 31(2)
$
i17
$
i7
$
i3
Change
in unrealized gains relating to instruments still held at December 31
$
i18
$
i11
$
i3
(1) Net
gains are included in Interest Income and net losses are included in Interest Expense on Sempra’s Consolidated Statements of Operations.
(2) Balance at December 31, 2022 includes $i7 in Other Current Assets and $i10
in Other Long-Term Assets. Balances at December 31, 2021 and 2020 include $ii7/
in Other Current Assets, offset by a negligible amount and $ii4/,
respectively, in Deferred Credits and Other on Sempra’s Consolidated Balance Sheets.
The fair value of the Support Agreement, net of related guarantee fees, is based on a discounted cash flow model using a probability of default and survival methodology. Our estimate of fair value considers inputs such as third-party default rates, credit ratings, recovery rates, and risk-adjusted discount rates, which may be readily observable, market corroborated or generally unobservable inputs. Because CFIN’s credit rating and related default and survival rates are unobservable inputs that are significant to the valuation, the Support Agreement, net of related guarantee fees, is classified as Level 3. We assigned CFIN an internally developed credit rating of A3 and relied on default rate data published by Moody’s to assign a probability of default. A hypothetical change in the credit rating up or
down one notch could result in a significant change in the fair value of the Support Agreement.
Fair Value of Financial Instruments
The fair values of certain of our financial instruments (cash, accounts receivable, amounts due to/from unconsolidated affiliates with original maturities of less than 90 days, 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(5)
i640
i—
i642
i—
i642
Long-term
amounts due to unconsolidated affiliates
i287
i—
i295
i—
i295
Total
long-term debt(2)
i20,099
i—
i22,126
i—
i22,126
SDG&E:
Total
long-term debt(3)
$
i6,417
$
i—
$
i7,236
$
i—
$
i7,236
SoCalGas:
Total
long-term debt(4)
$
i4,759
$
i—
$
i5,367
$
i—
$
i5,367
(1) Before
allowances for credit losses of $i7 and $i8 at December 31, 2022 and 2021,
respectively. Excludes unamortized transaction costs of $ii5/ at both December
31, 2022 and 2021.
(2) Before reductions of unamortized discount and debt issuance costs of $i289 and $i260
at December 31, 2022 and 2021, respectively, and excluding finance lease obligations of $i1,343 and $i1,335
at December 31, 2022 and 2021, respectively.
(3) Before reductions of unamortized discount and debt issuance costs of $i70 and $i61
at December 31, 2022 and 2021, respectively, and excluding finance lease obligations of $i1,256 and $i1,274
at December 31, 2022 and 2021, respectively.
(4) Before reductions of unamortized discount and debt issuance costs of $i48 and $i36
at December 31, 2022 and 2021, respectively, and excluding finance lease obligations of $i87 and $i61 at December 31, 2022 and 2021,
respectively.
(5) Before allowances for credit losses of $i1 at December 31, 2021. Includes $i2
of accrued interest receivable at December 31, 2021 in Due From Unconsolidated Affiliate – Current.
We provide the fair values for the securities held in the NDT related to SONGS in Note 15.
NOTE
13. iPREFERRED STOCK
Sempra and SDG&E are authorized to issue up to i50 million and i45
million shares of preferred stock, respectively. At December 31, 2022 and 2021, 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 MANDATORY CONVERTIBLE 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.
As of July 15, 2021, we had converted, pursuant to either early conversions at the election of the holder or the mandatory conversion of all outstanding shares, all i5,750,000
shares of series B preferred stock into an aggregate of i4,256,720 shares of our common stock and a nominal amount of cash in lieu of fractional share interests, based on a conversion rate of i0.7403
shares of our common stock for each issued and outstanding share of series B preferred stock. As a consequence, no shares of series B preferred stock were outstanding after July 15, 2021 and the i5,750,000 shares that were formerly series B preferred stock have returned to the status of authorized and unissued shares of preferred stock.
SEMPRA SERIES C PREFERRED STOCK
At December 31,
2022 and 2021, Sempra had ii900,000/
shares of ii4.875/% fixed-rate reset
cumulative redeemable perpetual preferred stock, series C (series C preferred stock) outstanding.
Liquidation Preference
Each share of series C preferred stock has a liquidation preference of $ii1,000/
plus any accumulated and unpaid dividends (whether or not declared) on such share.
Redemption at the Option of Sempra
The shares of series C preferred stock are perpetual and have no maturity date. However, we may, at our option, redeem the series C preferred stock in whole or in part, from time to time, on any day during the period from and including the July 15 immediately preceding October 15, 2025 and October 15 of every fifth year after 2025 through and including such October 15 at a redemption price in cash equal to $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. 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.
Voting Rights
The holders of series C preferred stock do not have any voting rights, except with respect to any authorization, creation or increase in the authorized amount of any class or series of capital stock ranking senior to the series C preferred stock, certain amendments to the terms of the series C preferred stock, in certain other limited circumstances and as otherwise specifically required by California
law. In addition, whenever dividends on any shares of series C preferred stock have not been declared and paid or have been declared but not paid for three or more dividend periods, whether or not consecutive, the authorized number of directors on our board of directors will automatically be increased by two and the holders of the series C preferred stock, voting together as a single class with holders of any and all other outstanding series of preferred stock of equal rank having similar voting rights, will be entitled to elect two directors who satisfy certain requirements to fill such two newly created directorships. This voting right will terminate when all accumulated and unpaid dividends on the series C preferred stock have been paid in full and, upon such termination and the termination of the same voting rights of all other holders of outstanding series of preferred
stock that have such voting rights, the term of office of each director elected pursuant to such rights will terminate and the authorized number of directors will automatically decrease by two, subject to the revesting of such rights in the event of each subsequent nonpayment.
Ranking
The series C preferred stock ranks, with respect to dividend rights and distribution rights upon our liquidation, winding-up or dissolution:
▪senior to our common stock and each other class or series of our capital stock established in the future, unless the terms of such capital stock expressly provide otherwise;
▪on
parity with each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks on parity with the series C preferred stock;
▪junior to each class or series of our capital stock established in the future, if the terms of such capital stock provide that it ranks senior to the series C preferred stock;
▪junior to our existing and future indebtedness and other liabilities; and
▪structurally subordinated to all existing and future indebtedness and other liabilities of our subsidiaries and capital stock of our subsidiaries held by third parties.
SOCALGAS PREFERRED STOCK
SoCalGas is authorized to issue up to
an aggregate of 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
- 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.
NOTE
14. iSEMPRA – SHAREHOLDERS’ EQUITY AND EARNINGS PER COMMON SHARE
SEMPRA COMMON STOCK REPURCHASES
On September 11, 2007, our board of directors authorized the repurchase of shares of our common stock, provided that the amounts spent for such purpose do not exceed the greater of $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 ASR program was completed on August
4,
2020 with an aggregate of i4,089,375 shares of Sempra 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 were repurchased under this authorization in 2020.
Beginning on November 17, 2021, we executed a series of open market repurchases for which we paid $i300 million
to repurchase shares of our common stock in the open market. The repurchases were completed on December 7, 2021 with an aggregate of i2,422,758 shares of Sempra common stock repurchased at a weighted-average purchase price of $i123.83
per share, excluding commissions.
On January 11, 2022, we entered into an ASR program under which we prepaid $i200 million to repurchase shares of our common stock in a share forward transaction. A total of i1,472,756
shares were purchased under this program at an average price of $i135.80 per share. The total number of shares purchased was determined by dividing the $i200 million
purchase price by the arithmetic average of the volume-weighted average trading prices of shares of our common stock during the valuation period of January 12, 2022 through February 11, 2022, minus a fixed discount. The ASR program was completed on February 11, 2022.
On April 6, 2022, we entered into an ASR program under which we prepaid $i250 million
to repurchase shares of our common stock in a share forward transaction. A total of i1,471,957 shares were purchased under this program at an average price of $i169.84
per share. The total number of shares purchased was determined by dividing the $i250 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 April 7, 2022 through April 25, 2022, minus a fixed discount. The ASR program was completed on April 25, 2022. As of February
28, 2023, a maximum of $i1.25 billion and no more than i19,632,529
shares may yet be purchased under the July 6, 2020 repurchase authorization.
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
$
i2,285
$
i1,463
$
i2,255
Earnings
attributable to noncontrolling interests
(i146)
(i145)
(i162)
Preferred
dividends
(i44)
(i63)
(i168)
Preferred
dividends of subsidiary
(i1)
(i1)
(i1)
Earnings
from continuing operations attributable to common shares
$
i2,094
$
i1,254
$
i1,924
Numerator
for discontinued operations:
Income from discontinued operations, net of income tax
$
i—
$
i—
$
i1,850
Earnings
attributable to noncontrolling interests
i—
i—
(i10)
Earnings
from discontinued operations attributable to common shares
$
i—
$
i—
$
i1,840
Numerator
for earnings:
Earnings attributable to common shares
$
ii2,094/
$
ii1,254/
$
ii3,764/
Denominator:
Weighted-average
common shares outstanding for basic EPS(1)
i315,159
i311,755
i291,077
Dilutive
effect of stock options and RSUs(2)
i1,219
i752
i1,175
Dilutive
effect of mandatory convertible preferred stock
i—
i529
i—
Weighted-average
common shares outstanding for diluted EPS
i316,378
i313,036
i292,252
Basic
EPS:
Earnings from continuing operations
$
i6.65
$
i4.03
$
i6.61
Earnings
from discontinued operations
$
i—
$
i—
$
i6.32
Earnings
$
i6.65
$
i4.03
$
i12.93
Diluted
EPS:
Earnings from continuing operations
$
i6.62
$
i4.01
$
i6.58
Earnings
from discontinued operations
$
i—
$
i—
$
i6.30
Earnings
$
i6.62
$
i4.01
$
i12.88
(1)
Includes fully vested RSUs held in our Deferred Compensation Plan of i403 in 2022, i453 in 2021 and i537
in 2020. These fully vested RSUs are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.
/
(2)Due to market fluctuations of both Sempra common stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based RSUs, which we discuss in Note 10, dilutive RSUs may vary widely from period-to-period.
The potentially dilutive impact from stock options and RSUs is calculated under the treasury stock method. Under this method, proceeds based on the exercise price and unearned
compensation are assumed to be used to repurchase shares on the open market at the average market price for the period, reducing the number of potential new shares to be issued and sometimes causing an antidilutive effect. The computation of diluted EPS for 2022, 2021 and 2020 excludes potentially dilutive shares related to stock options and RSUs of i86,532, i211,155
and i187,028, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future.
In 2021, the potentially dilutive impact from mandatory convertible preferred stock was calculated under the if-converted method until the mandatory conversion date. After the mandatory conversion date, the converted shares are included in weighted-average common shares
outstanding for basic EPS. As we discuss in Note 13, we converted our series A preferred stock into common
stock on January 15, 2021 and our series B preferred stock into common stock on July 15, 2021. The computation of diluted EPS for the years ended December 31, 2021 and 2020 excludes potentially
dilutive shares related to our mandatory convertible preferred stock of i2,272,117 and i17,889,365,
respectively, because to include them would be antidilutive for those periods.
We are authorized to issue i750 million shares of no par value common stock. iThe
following table provides common stock activity for the last three years.
COMMON STOCK ACTIVITY
2022
2021
2020
Sempra:
Common
shares outstanding, January 1
i316,919,782
i288,470,244
i291,712,925
Conversion
of mandatory convertible preferred stock
i—
i18,037,745
i—
Shares
issued in IEnova exchange offer
i—
i12,306,777
i—
RSUs
vesting(1)
i457,222
i686,916
i896,839
Stock
options exercised
i40,630
i50,671
i4,400
Savings
plan issuance
i—
i—
i201,431
Common
stock investment plan(2)
i—
i—
i42,955
Issuance
of RSUs held in our Deferred Compensation Plan
i65,013
i102,238
i103,552
Shares
repurchased(3)
(i3,147,969)
(i2,734,809)
(i4,491,858)
Common
shares outstanding, December 31
i314,334,678
i316,919,782
i288,470,244
(1) Includes
dividend equivalents.
(2) Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.
(3) Includes shares repurchased under the repurchase programs that we discuss above. Generally, we purchase shares of our common stock or units from LTIP participants who elect to sell to us a sufficient number of vested RSUs to meet minimum statutory tax withholding requirements.
NOTE
15. SAN ONOFRE NUCLEAR GENERATING STATION
SDG&E has a 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’s and SDG&E’s Consolidated Statements of Operations.
NUCLEAR DECOMMISSIONING AND FUNDING
As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison began the decommissioning phase of the plant. Major decommissioning work began in 2020. We expect the majority of the decommissioning work to take approximately i10
years. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be completed once Units 2 and 3 are dismantled and the spent fuel is removed from the site. The spent fuel is currently being stored on-site, until the DOE identifies a spent fuel storage facility and puts in place a program for the fuel’s disposal, as we discuss below. SDG&E is responsible for approximately i20% of the total decommissioning cost.
The Samuel Lawrence Foundation filed a writ petition under the
California Coastal Act in LA Superior Court in December 2019 seeking to invalidate the coastal development permit and to obtain injunctive relief to stop decommissioning work. The petition was denied in September 2021. In December 2021, the Samuel Lawrence Foundation filed a notice of appeal. In August 2022, the court dismissed the case based on the Samuel Lawrence Foundation’s request for dismissal, which finally resolves the writ petition. Decommissioning work was not interrupted as a result of this writ petition.
In accordance with state and federal requirements and regulations, SDG&E has assets held in the NDT to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. Amounts that were collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of externally managed trust funds. Amounts held by the NDT are invested in accordance
with CPUC regulations. SDG&E classifies debt and equity securities held in the NDT as available-for-sale. The NDT assets are presented on the Sempra and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in noncurrent Regulatory Liabilities.
Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In December 2022, the CPUC
granted SDG&E authorization to access NDT funds of up to $i81 million for forecasted 2023 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
i
The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT on the Sempra and SDG&E Consolidated Balance Sheets. We provide additional fair value disclosures for the NDT in Note 12.
Net
unrealized gains and losses, as well as realized gains and losses that are reinvested in the NDT, are included in noncurrent Regulatory Liabilities on Sempra’s and SDG&E’s Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.
ASSET RETIREMENT OBLIGATION
The present value of SDG&E’s ARO related to decommissioning costs for all three SONGS units was $i540 million at December 31, 2022
and is based on a cost study prepared in 2020 that is pending CPUC approval, which SDG&E expects to receive in 2023. The ARO for Units 2 and 3 reflects the acceleration of the start of decommissioning of these units as a result of the early closure of the plant. We expect SDG&E’s undiscounted SONGS decommissioning payments to be $i92 million in 2023, $i77
million in 2024, $i46 million in 2025, $i52 million in
2026, $i32 million in 2027, and $i686 million
thereafter.
U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL
Spent nuclear fuel from SONGS is currently stored on-site in an ISFSI licensed by the NRC. The ISFSI will operate until 2051, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS.
The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. In November 2019, Edison filed a claim for spent fuel management costs in the U.S. Court of Federal Claims
for the time period from January 2017 through July 2018, which is pending DOE approval. It is unclear when Edison will pursue litigation claims for spent fuel management costs incurred on or after August 1, 2018. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.
NUCLEAR INSURANCE
SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. Currently, this insurance provides $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.
The SONGS owners have nuclear property damage insurance of $i130
million, which exceeds the minimum federal requirement 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 $i4.1
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.
We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed, and in some cases have exceeded, applicable insurance coverage and could materially adversely affect our business, results of operations, financial condition, cash flows and/or prospects. Unless otherwise indicated, we are unable to reasonably estimate possible losses or a range of losses in excess of any amounts accrued.
At December 31, 2022, loss contingency accruals
for legal matters, including associated legal fees and regulatory matters related to the Leak, that are probable and estimable were $i281 million for Sempra, including $i205 million
for SoCalGas. Amounts for Sempra and SoCalGas include $i130 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.
Litigation – Resolved. In September 2021, SoCalGas and Sempra entered into an agreement with counsel to resolve approximately i390 lawsuits including approximately i36,000
plaintiffs (the Individual Plaintiffs) pending against SoCalGas and Sempra related to the Leak (the Individual Plaintiff Litigation) for a payment of up to $i1.8 billion.
These cases were coordinated before a single court in the LA Superior Court for pretrial management under a Third Amended Consolidated Master Case Complaint for Individual Actions filed in November 2017. 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 and wrongful death against SoCalGas and Sempra (the Individual Plaintiff Litigation). The complaint also asserted violations of Proposition 65, which were resolved in January 2022. The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs of future medical monitoring, civil penalties, and attorneys’ fees.
The agreement governing the settlement of the Individual Plaintiff Litigation requires each plaintiff who agrees to participate in the settlement to release all such plaintiff’s claims against SoCalGas, Sempra and their respective affiliates related to the Leak and the Individual Plaintiff Litigation. The Individual Plaintiffs who do not
participate in the settlement (the Remaining Individual Plaintiffs) will be able to continue to pursue their claims. Over i99% of the Individual Plaintiffs agreed to participate and submitted valid releases, and SoCalGas paid $i1.79
billion in 2022 under the agreement. As of February 21, 2023, approximately i265 of the Remaining Individual Plaintiffs had not been located or had failed to respond, according to plaintiffs’ counsel.
In September 2021, SoCalGas and Sempra entered into an agreement to settle a class action on behalf of persons and businesses who owned or leased real property within a five-mile radius of the well where the Leak occurred for a total amount of $i40
million. In April 2022, the LA Superior Court gave final approval of the settlement.
In October 2018 and October 2020, complaints on behalf of five property developers (the Developer Plaintiffs) were filed against SoCalGas and Sempra in connection with the Leak. The complaints alleged causes of action for strict liability, negligence per se, negligence, negligent interference, continuing nuisance, permanent nuisance, inverse condemnation and violation of the California Unfair Competition Law and California Public Utilities Code section 2106, and sought compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. In 2022, SoCalGas and Sempra settled the claims of all of the Developer Plaintiffs and their claims were dismissed.
Litigation – Unresolved.iFour
shareholder derivative actions were filed alleging breach of fiduciary duties against certain officers and certain directors of Sempra and/or SoCalGas. iThree of the ifour
shareholder derivative actions that were filed alleging breach of fiduciary duties against certain officers and certain directors of Sempra and/or SoCalGas were joined in an Amended Consolidated Shareholder Derivative Complaint filed in the coordinated proceeding in the LA Superior Court, which was
dismissed with prejudice in January 2021. The plaintiffs have appealed this dismissal. The LA Superior Court dismissed the remaining fourth action with prejudice in November 2022. The plaintiffs have
appealed this dismissal.
In addition, the Remaining Individual Plaintiffs referred to above will be able to continue to pursue their claims. Also, as of February 21, 2023, i14 new lawsuits on behalf of approximately i235
plaintiffs were filed since the September 2021 settlement.
Regulatory Proceedings – Subject to Agreements to Resolve. In June 2019, the CPUC opened an OII (the Leak OII) to investigate and consider, among other things, whether SoCalGas should be sanctioned for the Leak and what damages, fines or other penalties, if any, should be imposed for any violations, unreasonable or imprudent practices or failure to cooperate sufficiently with SED, as well as to determine the amount 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. In October 2022, SoCalGas executed a settlement agreement with SED and the Public Advocates Office at the CPUC to resolve all aspects of the Leak OII. The settlement agreement provides for financial penalties, certain
costs that SoCalGas will reimburse, a violation of California Public Utilities Code section 451, and costs previously incurred by SoCalGas for which it will not seek recovery from ratepayers, among other provisions. The settlement agreement was filed with and is subject to approval by the CPUC.
Regulatory Proceedings – Unresolved. In February 2017, the CPUC opened a proceeding pursuant to the SB 380 OII to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility while still maintaining energy and electric reliability for the region, but excluding issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Leak. The first phase of the proceeding established a framework for the hydraulic, production cost and economic modeling assumptions for the potential reduction in usage or elimination of the Aliso
Canyon natural gas storage facility, as well as evaluating the impacts of reducing or eliminating the Aliso Canyon natural gas storage facility using the established framework and models. The next phase of the proceeding included engaging a consultant to analyze alternative means for meeting or avoiding the demand for the facility’s services if it were eliminated in either the 2027 or 2035 timeframe, and to address potential implementation of alternatives to the Aliso Canyon natural gas storage facility if the CPUC determines that the Aliso Canyon natural gas storage facility should be permanently closed. The CPUC also added all California IOUs as parties to the proceeding and encouraged all load serving entities in the Los Angeles Basin to join the proceeding.
In November 2021, the CPUC issued a decision on the interim range of gas inventory levels at the Aliso Canyon natural gas storage facility, setting an interim range
of gas inventory levels of up to 41.16 Bcf. The CPUC may issue future changes to this interim range of authorized gas inventory levels before issuing a final inventory determination within the SB 380 OII proceeding.
At December 31, 2022, the Aliso Canyon natural gas storage facility had a net book value of $i958 million. If the Aliso Canyon natural gas storage facility were to be permanently
closed or if future cash flows from its operation were otherwise insufficient to recover its carrying value, we may record an impairment of the facility, which could be material, or we could incur materially higher than expected operating costs and/or be required to make material additional capital expenditures (any or all of which may not be recoverable in rates), and natural gas reliability and electric generation could be jeopardized.
Cost Estimate, Insurance and Accounting and Other Impacts. SoCalGas has incurred significant costs related to the Leak, primarily to defend against and settle civil and criminal litigation and regulatory proceedings arising from the Leak; 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 pay the costs of the government-ordered
response to the Leak, including the costs for a root cause analysis; 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, 2022, SoCalGas estimates these costs related to the Leak are $i3,486 million (the cost estimate), including $i1,279
million of costs recovered from insurance. Other than insurance for directors’ and officers’ liability, we have exhausted all of our insurance for 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. At December 31, 2022, $i129 million of the cost estimate is accrued in Reserve for Aliso Canyon Costs and $i4
million of the cost estimate is accrued in Deferred Credits and Other on SoCalGas’ and Sempra’s Consolidated Balance Sheets.
SoCalGas recorded total charges of $i259 million ($i199
million after tax), $i1.59 billion ($i1.15 billion after tax) and $i307 million
($i233 million after tax) in the years ended December 31, 2022, 2021 and 2020, respectively, in Aliso Canyon Litigation and Regulatory Matters on the SoCalGas and Sempra Consolidated Statements of Operations related to the litigation and regulatory proceedings that we describe above. These charges are included in the cost estimate.
Except for the amounts paid or
estimated to settle certain legal and regulatory matters as described above, the cost estimate does not include any amounts necessary to resolve the matters that we describe above in “Litigation – Unresolved” and “Regulatory Proceedings – Unresolved,” threatened litigation, other potential litigation or other costs, in each case to the extent it is not possible to predict at this time the outcome of these actions or reasonably estimate the possible costs or a range of possible costs.
Further,
we are not able to reasonably estimate the possible loss or a range of possible losses in excess of the amounts accrued. The costs or losses not included in the cost estimate could be significant.
An adverse outcome with respect to (i) the litigation described above under “Litigation – Unresolved,” (ii) threatened or other potential litigation related to the Leak, (iii) the Leak OII if approval of the negotiated settlement is not obtained, or (iv) the unresolved proceeding pursuant to the SB 380 OII, could have a material adverse effect on SoCalGas’ and Sempra’s results of operations, financial condition, cash flows and/or prospects.
Sempra Infrastructure
Energía Costa Azul
We
describe below certain land and customer disputes and permit challenges affecting our ECA Regas Facility. Certain of these land disputes involve land on which portions of the ECA LNG liquefaction facilities under construction and in development are expected to be situated or on which portions of the ECA Regas Facility that would be necessary for the operation of such ECA LNG liquefaction facilities are situated. One or more unfavorable final decisions on these disputes or challenges could materially adversely affect our existing natural gas regasification operations and proposed natural gas liquefaction projects at the site of the ECA Regas Facility and have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Land Disputes – Unresolved.
Sempra Infrastructure has been engaged in a long-running land dispute relating to property adjacent to its ECA Regas Facility that allegedly overlaps with land owned by the ECA Regas Facility (the facility, however, is not situated on the land that is the subject of this dispute), as follows:
▪A claimant to the adjacent property filed complaints in the federal Agrarian Court challenging the refusal of SEDATU in 2006 to issue title to him for the disputed property. In November 2013, the federal Agrarian Court ordered that SEDATU issue the requested title to the claimant and cause it to be registered. Both SEDATU and Sempra Infrastructure challenged the ruling due to lack of notification of the underlying process. In May 2019, a federal court in Mexico reversed the ruling and ordered a retrial, which is pending resolution.
▪In
a separate proceeding, the claimant filed suit to reinitiate an administrative procedure at SEDATU to obtain the property title that was previously dismissed. In April 2021, the Agrarian Court ordered that the administrative procedure be restarted. The proceeding in the Agrarian Court has concluded; however, the administrative procedure at SEDATU may continue if SEDATU decides to reopen the matter.
In addition, a case involving an area of real property on which part of the ECA Regas Facility is situated is subject to a claim in the federal Agrarian Court, in which the plaintiff seeks to annul the property title for a portion of the land on which the ECA Regas Facility is situated and to obtain possession of a different parcel that allegedly overlaps with the site of the ECA Regas Facility. The proceeding, which seeks an order that SEDATU annul the ECA Regas Facility’s competing property title, was initiated in 2006 and, in
July 2021, a decision was issued in favor of the ECA Regas Facility. The plaintiff appealed, and in February 2022, the appellate court confirmed the ruling in favor of the ECA Regas Facility and dismissed the appeal. The plaintiff filed a federal appeal against the appellate court ruling. A ruling from the Federal Collegiate Circuit Court is pending.
Land Disputes – Resolved. Three cases involving an area of real property on which part of the ECA Regas Facility is situated, each brought by a single plaintiff or her descendants, were filed against the facility. The disputed area, which is a parcel adjacent to the ECA Regas Facility that allegedly overlaps with land on which the ECA Regas Facility is situated and also adjacent to the parcel subject to the unresolved Agrarian Court proceeding described in the preceding paragraph, is subject to a claim in the federal Agrarian Court and two claims in Mexican
civil courts. The ECA Regas Facility first bought the property from the federal government in 2003; however, to resolve an ownership controversy, in 2008, the ECA Regas Facility reached a financial settlement with the plaintiff to eliminate an adverse claim to its title. Nevertheless, the plaintiff sued in 2013 for the nullity of both titles. The Agrarian Court ruled in favor of the plaintiff in May 2021, nullifying the first property title. Sempra Infrastructure appealed the ruling in July 2021. In May 2022, Sempra Infrastructure won the appeal and the plaintiff’s claims were dismissed, thereby concluding the Agrarian Court proceeding. The ECA Regas Facility continues to hold the second property title to the land. The two civil court proceedings seek to invalidate the contract by which the ECA Regas Facility purchased for the second time the applicable parcel of land on which the ECA Regas Facility is situated on the grounds that the purchase price was allegedly unfair.
In the first civil case, initiated in 2013, the court ruled in favor of the ECA Regas Facility, and the final decision was affirmed on a federal appeal, thereby concluding the first civil case. The descendants of the same plaintiff filed the second civil case in 2019, which was dismissed by the court. However, the dismissal was appealed. In April 2022, the ECA Regas Facility entered into a settlement agreement with the plaintiff, whereby the plaintiff has agreed to recognize the ECA Regas Facility as the sole owner of the property and waive any current or future rights over the property, or any other properties related
to
the ECA Regas Facility. The settlement agreement has been approved by the court, thereby concluding the remaining civil case.
Environmental and Social Impact Permits – Unresolved. Several administrative challenges are pending before Mexico’s Secretariat of Environment and Natural Resources (the Mexican environmental protection agency) and Federal Tax and Administrative Courts, seeking revocation of the environmental impact authorization issued to the ECA Regas Facility in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.
In 2018 and 2021, three
related claimants filed separate challenges in the federal district court in Ensenada, Baja California in relation to the environmental and social impact permits issued by each of ASEA and SENER to ECA LNG authorizing natural gas liquefaction activities at the ECA Regas Facility, as follows:
▪In the first case, the court issued a provisional injunction in September 2018. In December 2018, ASEA approved modifications to the environmental permit that facilitate the development of the proposed natural gas liquefaction facility in two phases. In May 2019, the court canceled the provisional injunction. The claimant appealed the court’s decision canceling the injunction but was not successful. The claimant’s underlying challenge to the permits remains pending.
▪In the second case, the initial request for a provisional injunction
was denied. That decision was reversed on appeal in January 2020, resulting in the issuance of a new injunction against the permits that were issued by ASEA and SENER. This injunction has uncertain application absent clarification by the court. The claimants petitioned the court to rule that construction of natural gas liquefaction facilities violated the injunction, and in February 2022, the court ruled in favor of the ECA Regas Facility, holding that the natural gas liquefaction activities did not violate the injunction. The claimants have appealed this ruling.
▪In the third case, a group of residents filed a complaint in June 2021 against various federal and state authorities alleging deficiencies in the public consultation process for the issuance of the permits. The request for an initial injunction was denied and the claimants have appealed, which is pending the appellate court’s ruling.
Customer
Dispute – Resolved. In May 2020, the two third-party capacity customers at the ECA Regas Facility, Shell Mexico and Gazprom, asserted that a 2019 update of the general terms and conditions for service at the facility, as approved by the CRE, resulted in a breach of contract by Sempra Infrastructure and a force majeure event. In July 2020, Shell Mexico submitted a request for arbitration of the dispute, and Gazprom joined the proceeding, and a hearing was held in October 2021. The International Court of Arbitration issued a final, non-appealable decision in April 2022 in favor of Sempra Infrastructure dismissing all claims and confirming the contracts remain in force. In August 2022, the International Court of Arbitration issued an additional decision dismissing a request by Shell Mexico and Gazprom to consider additional arguments.
Citing the alleged breach, Shell Mexico stopped making payments under
its LNG storage and regasification agreement. Due to nonpayment, Sempra Infrastructure drew against Shell Mexico’s letters of credit provided as payment security until they were fully exhausted in March 2022. In September 2022, Shell Mexico paid its invoices from March 2022 through August 2022, bringing its account to current, resumed paying invoices as they come due, and renewed its letters of credit. Although Gazprom had previously been making regular monthly payments under its LNG storage and regasification agreement, Sempra Infrastructure drew against and fully exhausted Gazprom’s letters of credit in April 2022 due to Gazprom’s non-renewal of such letters of credit as required under the agreement. Gazprom did not pay its invoices from March 2022 through July 2022, so funds drawn from the letters of credit were used to fully offset such nonpayment. In September 2022, Gazprom paid its August 2022 invoice, bringing its account to current, and resumed paying invoices
as they come due. Subsequent invoices, if not paid by Gazprom, will be offset by funds drawn from the letters of credit. In November 2022, the German government nationalized the parent company of Gazprom, Gazprom Germania (rebranded as “Securing Energy for Europe”), to help stabilize Gazprom’s finances.
In addition to the arbitration proceeding, Shell Mexico also filed constitutional claims against the CRE’s approval of the general terms and conditions for service at the facility and against the issuance of the liquefaction permit. Shell Mexico’s request for an injunction against the general terms and conditions was denied, and the ruling was upheld on appeal. The request for an injunction against the liquefaction permit was denied, and the decision was vacated and remanded on appeal to the First District Court in Administrative Matters, which again denied the injunction. The case on the injunction request was then heard
again by the appellate court and was denied, making the decision final.
Sonora Pipeline
Guaymas-El Oro Segment – Unresolved. Sempra Infrastructure’s Sonora natural gas pipeline consists of two segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. In 2015, the Yaqui tribe, with the exception of some members living in the Bácum community, granted its consent and a right-of-way easement agreement for the construction of the Guaymas-El Oro segment of the Sonora natural gas pipeline that
crosses its territory. Representatives of the Bácum community filed a legal challenge in Mexican federal court demanding the right to withhold consent for the project, the stoppage of work in the Yaqui territory and damages. In 2016, the judge granted a suspension order that prohibited the construction of such segment through the Bácum community territory. Because the pipeline does not pass through the Bácum community, Sempra Infrastructure did not believe the 2016 suspension order prohibited construction in the remainder of the Yaqui territory. Construction of the Guaymas-El Oro segment was completed, and commercial operations began in May 2017.
Following the start of commercial operations of the Guaymas-El Oro segment, Sempra
Infrastructure reported damage to the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory that has made that section inoperable since August 2017 and, as a result, Sempra Infrastructure declared a force majeure event. In 2017, an appellate court ruled that the scope of the 2016 suspension order encompassed the wider Yaqui territory, which has prevented Sempra Infrastructure from making repairs to put the pipeline back in service. In July 2019, a federal district court ruled in favor of Sempra Infrastructure and held that the Yaqui tribe was properly consulted and that consent from the Yaqui tribe was properly received. Representatives of the Bácum community appealed this decision, causing the suspension order preventing Sempra Infrastructure from repairing the damage to the Guaymas-El Oro segment of the Sonora pipeline in the Yaqui territory to remain in place until the appeals process is exhausted. In December 2021, the court of appeals referred the
matter to Mexico’s Supreme Court. In June 2022, the Supreme Court remanded the case back to the court of appeals for final resolution. The CFE asked the court of appeals to dismiss the Bácum community’s appeal based on the plan to re-route the portion of the pipeline that is in the Yaqui territory. In December 2022, the court of appeals reversed the federal district court’s ruling and ordered the district court to issue a new ruling that takes into account the planned re-routing of the pipeline.
Sempra Infrastructure exercised its rights under the contract, which included seeking force majeure payments for the two-year period such force majeure payments were required to be made, which ended in August 2019.
In July 2019, the CFE filed a request for arbitration generally to nullify certain contract terms that provide for fixed capacity payments in instances of force majeure and made
a demand for substantial damages in connection with the force majeure event. In September 2019, the arbitration process ended when Sempra Infrastructure and the CFE reached an agreement to restart natural gas transportation service in January 2020 as the new service start date, and to modify the tariff structure and extend the term of the contract by 10 years. Subsequently, Sempra Infrastructure and the CFE agreed to extend the service start date multiple times, most recently to May 31, 2023. Under the revised agreement, the CFE will resume making payments only when the damaged section of the Guaymas-El Oro segment of the Sonora pipeline is back in service. If the pipeline is not back in service or the parties do not agree on a new service start date by May 31, 2023, Sempra Infrastructure retains the right to terminate the contract and seek to recover its reasonable and
documented costs and lost profits. Discussions with the CFE regarding the future of the pipeline are underway in accordance with a non-binding MOU announced in January 2022 that, among other matters, addresses efforts to restart service on the pipeline. In July 2022, Sempra Infrastructure and the CFE entered into a Shareholders’ Agreement that establishes a framework for a JV between the parties to work on restarting service on the pipeline, including the re-routing of a portion of the pipeline. This agreement is subject to a number of conditions to be satisfied before it becomes effective, including regulatory and corporate authorizations.
At December 31, 2022, Sempra Infrastructure had $i420
million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if Sempra Infrastructure is unable to re-route a portion of the pipeline (which has not been agreed to by the parties, but is subject to negotiation pursuant to a non-binding MOU and a Shareholders’ Agreement, as described above) and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery, which in each case could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Sasabe-Puerto Libertad-Guaymas Segment – Resolved. In June 2014, Sempra Infrastructure and a landowner agreed to enter into a voluntary right-of-way easement agreement for the construction
and operation of a seven-mile section of the 314-mile Sasabe-Puerto Libertad-Guaymas segment of the Sonora natural gas pipeline on the landowner’s property. However, in 2015, the landowner filed a complaint demanding the easement agreement be nullified. In September 2021, a definitive and non-appealable judgment was issued declaring the easement agreement nullified and ordering the removal of the pipeline from the landowner’s property. The execution of the judgment was suspended as a result of an amparo lawsuit filed by the CFE as an interested third party that did not participate in the litigation. Sempra Infrastructure filed a special judicial action asking the civil court to acknowledge the existence of the easement and to determine the consideration the landowner should receive in exchange for the easement. In July 2022, Sempra Infrastructure and the landowner entered into a new easement agreement approved by the court for the seven-mile section on the landowner’s
property, thus bringing this case to definitive conclusion.
Litigation Related to Regulatory and Other Actions by the Mexican Government – Unresolved
Amendments to Mexico’s Electricity Industry Law. In March 2021, the Mexican government published a decree with amendments to Mexico’s Electricity Industry Law
that include some public policy changes, including establishing priority of dispatch for CFE plants over privately owned plants. According to the decree, these amendments were to become effective on March 10, 2021, and SENER, the CRE and Centro Nacional de Control de Energía (Mexico’s National Center for Energy Control) were to have 180 calendar days to modify, as necessary, all resolutions, policies, criteria, manuals and other regulations applicable to the power industry to conform with this decree. However, a Mexican court issued a suspension of the amendments on March 19, 2021. In April 2022, the Mexican Supreme Court resolved an action of unconstitutionality filed by a group of senators against the amended Electricity Industry Law, but the qualified majority of eight votes out of 11 as is required in matters involving constitutionality was not reached and the proceeding
was dismissed, which means that the Mexican Supreme Court did not issue a binding precedent and the amended Electricity Industry Law remains in force. Sempra Infrastructure filed three lawsuits against the amendments to the Electricity Industry Law and, in each of them, Sempra Infrastructure obtained a favorable judgment in the lower courts, which has been appealed. If the proposed amendments are affirmed by the lower courts or by the Mexican Supreme Court (which in these cases would only require a simple majority vote), the CRE may be required to revoke self-supply permits granted under the former electricity law, which were grandfathered when the new Electricity Industry Law was enacted, under a legal standard that is ambiguous and not well defined under the law. If such self-supply permits granted under the former electricity law are revoked, it may result in increased costs for Sempra Infrastructure and its customers, may adversely affect our ability to develop new
projects, may result in decreased revenues and cash flows, and may negatively impact our ability to recover the carrying values of our investments in Mexico, any of which could have a material adverse effect on Sempra’s business, results of operations, financial condition, cash flows and/or prospects.
Litigation Related to Regulatory and Other Actions by the Mexican Government – Resolved
Transmission Rates for Legacy Generation Facilities. In May 2020, the CRE approved an update to the transmission rates included in legacy renewable and cogeneration energy contracts based on the claim that the legacy transmission rates did not reflect fair and proportional costs for providing the applicable services and, therefore, created inequitable competitive
conditions. Three of Sempra Infrastructure’s renewable energy facilities (Don Diego Solar, Border Solar and Ventika) are currently holders of contracts with such legacy rates, and under the terms of these contracts any increases in the transmission rates would be passed through directly to their customers. These renewable energy facilities sought and obtained injunctive relief but were required to guarantee the difference in tariffs. The three facilities obtained favorable resolutions from a lower court and the CRE appealed those decisions, which were definitively affirmed in favor of the Don Diego Solar, Border Solar and Ventika facilities, whereby the injunctions were made permanent, the regulations were declared unconstitutional, and the guarantee was determined to not be required. There are no further opportunities to appeal and therefore these resolutions are final.
Offtakers
of Legacy Generation Permits. In October 2020, the CRE approved a resolution to amend the rules for the inclusion of new offtakers of legacy generation and self-supply permits (the Offtaker Resolution), which became effective immediately. The Offtaker Resolution prohibits self-supply permit holders from adding new offtakers that were not included in the original development or expansion plans, making modifications to the amount of energy allocated to the named offtakers, and including load centers that have entered into a supply arrangement under Mexico’s Electricity Industry Law. Don Diego Solar, Border Solar and Ventika are holders of self-supply permits, and the itwo
solar facilities are currently affected by the Offtaker Resolution. In January 2022, Don Diego Solar and Border Solar obtained injunctive relief and a favorable resolution from a Mexican federal district court and the CRE appealed that decision. In December 2022, the court of appeals definitively resolved the case by confirming the federal district court’s judgment in favor of Don Diego Solar and Border Solar and there are no further opportunities to appeal and therefore this resolution is final.
Amendments to Mexico’s Hydrocarbons Law. In May 2021, amendments to Mexico’s Hydrocarbons Law were published and became effective. The amendments grant SENER and the CRE additional powers to suspend and revoke permits related to the midstream and downstream sectors. Suspension of permits will
be determined by SENER or the CRE when a danger to national security, energy security, or to the national economy is foreseen. Likewise, new grounds for the revocation of permits are in place if the permit holder (i) carries out its activity with illegally imported products; (ii) fails, on more than one occasion, to comply with the provisions applicable to quantity, quality and measurement of the products; or (iii) modifies the technical conditions of its infrastructure without authorization. Additionally, in the case of existing permits, authorities will revoke those permits that fail to comply with the minimum storage requirements established by SENER or fail to comply with requirements or violate provisions established by the amended Hydrocarbons Law. All the Sempra Infrastructure entities participating in the Mexico hydrocarbons sector filed lawsuits against the initiative to reform the Hydrocarbons Law. In 2021, district courts issued judgments that the amendments
do not affect the interests of the companies at this time and, as a result, dismissed the amparo lawsuits, including the lawsuits filed by the Sempra Infrastructure entities. The Sempra Infrastructure entities have appealed these
judgments. The Circuit Courts upheld the dismissal of the amparo lawsuits and there are no further opportunities to appeal, thereby concluding the amparo lawsuits.
Other
Litigation – Unresolved
RBS Sempra Commodities
Sempra holds an equity method investment in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. In 2015, liquidators filed a claim in the High Court of Justice against RBS (now NatWest Markets plc, our partner in the JV) 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, a subsidiary of RBS Sempra Commodities. 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
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 £i45 million (approximately $i54
million in U.S. dollars at December 31, 2022), plus costs and interest. In October 2020, the High Court of Justice assessed costs and interest to be approximately £i21 million (approximately $i25
million in U.S. dollars at December 31, 2022) as of that date, with interest continuing to accrue. The Defendants appealed and, in May 2021, the Court of Appeal set aside the High Court of Justice’s decision and ordered a retrial. In July 2022, the Supreme Court of the U.K. denied the Liquidating Companies application for permission to appeal the Court of Appeal’s decision. No date has been scheduled for the retrial. J.P. Morgan Chase & Co., which acquired RBS SEE and later sold it to Mercuria Energy Group, Ltd., previously notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and J.P. Morgan Chase & Co. has in turn sought indemnity from Sempra and RBS.
We recorded $i100
million in equity losses from our investment in RBS Sempra Commodities in Equity Earnings on Sempra’s Consolidated Statement of Operations in 2020, which represented an estimate of our obligations to settle pending VAT matters and related legal costs. In 2021, we reduced this estimate by $i50 million based on a related settlement with HMRC on the First-Tier Tribunal case and revised assumptions on the High Court of Justice case.
Asbestos Claims Against EFH Subsidiaries
Certain
EFH subsidiaries that we acquired as part of the merger of EFH with an indirect subsidiary of Sempra were defendants in personal injury lawsuits brought in state courts throughout the U.S. These cases alleged illness or death as a result of exposure to asbestos in power plants designed and/or built by companies whose assets were purchased by predecessor entities to the EFH subsidiaries, and generally assert claims for product defects, negligence, strict liability and wrongful death. They sought compensatory and punitive damages. As of February 21, 2023, itwo
lawsuits are pending. Additionally, in connection with a December 2015 deadline in 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 or claims and the amount of damages that may be imposed or incurred could have a material adverse effect on Sempra’s results of operations,
financial condition, cash flows and/or prospects.
Ordinary Course Litigation
We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.
LEASES
A lease exists when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. We determine if an arrangement is or contains a lease at inception of the contract.
Some of our lease
agreements contain nonlease components, which represent activities that transfer a separate good or service to the lessee. iAs 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 refined products
terminals if the timing and pattern of transfer of the lease and nonlease components are the same and the lease component would be classified as an operating lease if accounted for separately.
Lessee Accounting
We have operating and finance leases for real and personal property (including office space, land, fleet vehicles, machinery and equipment, warehouses and other operational
facilities) and PPAs with renewable energy, energy storage and peaker plant facilities.
Some of our leases include options to extend the lease terms for up to i25 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.
Certain of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. We do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. In such cases, we recognize short-term lease costs on a straight-line basis over the lease term. Our short-term lease costs for the period reasonably reflect our short-term lease commitments.
Certain of our leases contain escalation clauses requiring annual increases in rent ranging from i2%
to i7% 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 2023 and 2024, $i296 million in 2025, $i290 million in 2026, $i289 million
in 2027 and $i2,496 million thereafter.
As of the lease commencement date, we recognize a lease liability for our obligation to make future lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal
to the lease payments in a similar economic environment. We also record a corresponding ROU asset, initially equal to the lease liability and adjusted for lease payments made at or before lease commencement, lease incentives, and any initial direct costs. We test ROU assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of the ROU assets.
For our operating leases, our non-regulated entities recognize a single lease cost on a straight-line basis over the lease term in operating expenses. SDG&E and SoCalGas recognize this single lease cost on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.
For our finance leases, the interest expense on the lease liability and amortization of the ROU asset are accounted for separately.
Our non-regulated entities use the effective interest rate method to account for the imputed interest on the lease liability and amortize the ROU asset on a straight-line basis over the lease term. SDG&E and SoCalGas recognize amortization of the ROU asset on a basis that is consistent with the recovery of such costs in accordance with U.S. GAAP governing rate-regulated operations.
Our leases do not contain any material residual value guarantees, restrictions or covenants.
Classification
of ROU assets and lease liabilities and the weighted-average remaining lease term and discount rate associated with operating and finance leases are summarized in the table below.
LESSEE
INFORMATION ON THE CONSOLIDATED BALANCE SHEETS
(2) Included in O&M, except for $i25 at Sempra, $i24 at SDG&E
and $i1 at SoCalGas in 2022, $i22 at Sempra, $i21
at SDG&E and $i1 at SoCalGas in 2021, and $ii18/
at Sempra and SDG&E in 2020, which is included in Depreciation and Amortization Expense.
(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 and supplemental noncash information were as follows:
LESSEE
INFORMATION ON THE CONSOLIDATED STATEMENTS OF CASH FLOWS
(1) Includes
$iiiii12////
in each of 2023 through 2027 and $i94 thereafter related to purchased-power contracts.
(2) Substantially all amounts are related to purchased-power contracts.
//
Leases
That Have Not Yet Commenced
SDG&E has entered into two energy storage tolling agreements, of which SDG&E expects one will commence in the first quarter of 2023 and one will commence in the third quarter of 2023. SDG&E expects the future minimum lease payments to be $i12 million in 2023, $iiii15/// million
in each of 2024 through 2027 and $i78 million thereafter until expiration in 2033.
SoCalGas has entered into a fleet vehicle agreement, under which SoCalGas expects leases will commence in the first quarter of 2023 through the fourth quarter of 2023. SoCalGas expects the future minimum lease payments to be $i1 million
in 2023, $iiiii2//// million
in each of 2024 through 2027 and $i9 million thereafter until expiration in 2031.
Lessor Accounting
Sempra Infrastructure is a lessor for certain of its natural gas and ethane pipelines, compressor stations, LPG storage facilities, a rail facility and refined products terminals, which we account for as operating or sales-type leases. These leases expire at various dates from 2026 through 2042.
Over
the lease term, we monitor the underlying assets in operating leases for impairment, and we evaluate the net investment in sales-type leases for expected credit losses. Sempra Infrastructure expects to continue to derive value from the underlying assets associated with its pipelines following the end of their respective lease terms based on the expected remaining useful life, expected market conditions and plans to re-market and re-contract the underlying assets.
iGenerally, we recognize operating lease income on a straight-line basis over the lease term, and sales-type lease income based on the effective interest
method over the lease term. Certain of our leases contain rate adjustments or are based on foreign currency exchange rates that may result in lease payments received that vary in amount from one period to the next. In addition to minimum fixed payments, our refined products terminals receive variable lease payments for barrels delivered that exceed minimum delivery requirements.
In July 2021, a rail facility agreement commenced, which Sempra Infrastructure is accounting for as a sales-type lease. The rail facility is being used by the lessee to transport refined products out of the Veracruz terminal. The lessee has the right to direct the use of the rail facility and will obtain substantially all of the economic benefits of the rail facility. At lease commencement, Sempra Infrastructure derecognized the $i44 million
carrying value of the rail facility from PP&E and recognized a net investment in sales-type lease asset of $i62 million and a selling profit of $i18
million. The agreement expires in 2041 and will automatically renew for successive five-year terms unless written notice is provided by Sempra Infrastructure or the lessee. Fixed lease payments are payable in the first five years of the agreement, which the lessee is required to pay even in the event of lease termination.
(1)
Included in 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.
SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2032.
Sempra Infrastructure has various capacity agreements for natural
gas storage and transportation that expire at various dates through 2059. Transportation costs on these agreements vary based on pipeline capacity.
Payments on our natural gas contracts could exceed the minimum commitment based on portfolio needs. iAt December 31, 2022, the future minimum payments under existing natural gas contracts and natural gas storage and transportation contracts are as follows:
FUTURE
MINIMUM PAYMENTS
(Dollars in millions)
Sempra
SoCalGas
Storage and transportation
Natural gas(1)
Total(1)
Transportation
Natural
gas
Total
2023
$
i202
$
i139
$
i341
$
i132
$
i4
$
i136
2024
i184
i49
i233
i114
i22
i136
2025
i144
i31
i175
i77
i21
i98
2026
i141
i—
i141
i75
i—
i75
2027
i138
i—
i138
i72
i—
i72
Thereafter
i795
i—
i795
i240
i—
i240
Total
minimum payments
$
i1,604
$
i219
$
i1,823
$
i710
$
i47
$
i757
(1)Excludes
amounts related to the LNG purchase agreement that we discuss below.
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 and SoCalGas were as follows:
Sempra Infrastructure has an SPA 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 2023 to 2029. Although this agreement specifies a number of cargoes to be delivered, under its terms, the supplier may divert certain cargoes, which would reduce amounts paid under the agreement by Sempra Infrastructure.
i
At December 31, 2022, the following LNG
commitment amounts are based on the assumption that all LNG cargoes, less those already confirmed to be diverted as of February 21, 2023, under the agreement are delivered:
LNG COMMITMENT AMOUNTS
(Dollars in millions)
Sempra:
2023
$
i1,068
2024
i797
2025
i802
2026
i796
2027
i787
Thereafter
i1,307
Total
$
i5,557
/
Actual
LNG purchases were approximately $i108 million in 2022, $i27 million
in 2021 and $i16 million in 2020 due to the supplier electing to divert cargoes as allowed by the agreement.
Payments on SDG&E’s purchased-power contracts could exceed the minimum commitments based on energy needs. These purchased-power contracts expire on various dates through 2042. iAt December 31, 2022, the future minimum payments under long-term purchased-power contracts for Sempra and SDG&E are as follows:
(1) Excludes
purchase agreements accounted for as operating leases and finance leases.
Payments on these contracts represent capacity charges and minimum energy and transmission purchases that exceed the minimum commitment. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. SDG&E estimates these variable payments to be $iiiii77//// million
in each of 2023 through 2027 and $i564 million thereafter. Total payments under purchased-power contracts for Sempra and SDG&E were $i484
million in 2022, $i495 million in 2021 and $i534 million in 2020.
Construction and Development Projects
Sempra has various capital projects in progress in the U.S. and Mexico. Our total contractual commitments at December 31, 2022 under these projects are approximately $i241 million, requiring future payments of $i87
million in 2023, $i24 million in 2024, $i20
million in 2025, $i20 million in 2026, $i19
million in 2027 and $i71 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to such projects.
SDG&E
At December 31, 2022, SDG&E has commitments to make future payments of $i33
million for construction projects that include:
▪$i25 million related to spent fuel management at SONGS; and
▪$i8
million for infrastructure improvements for electric transmission and distribution systems.
SDG&E expects future payments under these contractual commitments to be $i10 million in 2023, $iii1//
million in each of 2024 through 2026, $i2 million in 2027 and $i18
million thereafter.
SoCalGas
At December 31, 2022, SoCalGas has commitments to make future payments of $i12 million for an information technology software project. SoCalGas expects future payments under this contractual commitment to be $ii4/
million in each of 2023 and 2024 and $ii2/
million in each of 2025 and 2026.
Sempra Infrastructure
At December 31, 2022, Sempra Infrastructure has commitments to make future payments of $i196 million for construction and development projects that include:
▪$i16
million for refined products terminals;
▪$i174 million for natural gas pipelines and ongoing maintenance services; and
▪$i6
million for renewables and other projects.
Sempra Infrastructure expects future payments under these contractual commitments to be $i73 million in 2023, $i19
million in 2024, $iii17//
million in each of 2025 through 2027 and $i53 million thereafter.
We discuss nuclear insurance and nuclear fuel disposal related to SONGS in Note 15.
Fire Mitigation Fund
In connection with the completion of the Sunrise Powerlink project in 2012, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments, for which a liability has been recorded, are expected to be $iiiii4////
million per year in 2023 through 2027 and $i271 million thereafter, subject to escalation of i2% per year, ending in 2069. At December 31,
2022, the present value of these future payments of $i123 million has been recorded as a regulatory asset as the amounts represent a cost that we expect will be recovered from customers in the future.
Franchise Agreements
In July 2021, SDG&E’s natural gas and electric franchise agreements for the City of San Diego went into effect. These franchise agreements provide SDG&E the opportunity to
serve the City of San Diego for a period of 20 years, consisting of 10-year agreements that will automatically renew for an additional 10 years unless the City Council voids the automatic renewals with a supermajority vote. At December 31, 2022, SDG&E has commitments to make future principal and interest payments as consideration for the franchise agreements of $i14 million in 2023, $ii15/ million
in each of 2024 and 2025, $i4 million in 2026, $i2 million in 2027 and $i50 million
thereafter. The consideration paid will not be recovered from customers and will be amortized over 20 years.
In 2021, two lawsuits were filed in the California Superior Court challenging various aspects of the natural gas and electric franchise agreements granted by the City of San Diego to SDG&E. Both lawsuits ultimately sought to void the franchise agreements. In one of the cases, judgment was granted in favor of SDG&E and the City of San Diego. A final ruling is pending on the second case.
SoCalGas
In May 2022, SoCalGas’ new gas franchise agreement with the City of Los Angeles (City of LA) went into effect. This franchise agreement provides SoCalGas a gas system franchise to install, retain, operate and maintain its gas system within the City of LA for 21 years, consisting of a 13-year term that will automatically renew for an
additional eight years unless the City of LA exercises its option to terminate the renewal term. At December 31, 2022, SoCalGas has one remaining future payment obligation of $i11 million to be paid within 30 days of commencement of the eight-year renewal term in 2035 (if the renewal term is not terminated by the City of LA). This future payment obligation would not be recovered from customers and would be amortized over eight years.
Sempra Infrastructure
Additional
consideration for a 2006 comprehensive legal settlement with California to resolve the Continental Forge litigation included an agreement that, for a period of i18 years beginning in 2011, Sempra Infrastructure would sell to SDG&E and SoCalGas, subject to annual CPUC approval, up to i500
MMcf per day of regasified LNG from Sempra Infrastructure’s ECA Regas Facility that is not delivered or sold in Mexico at the price indexed to the California border minus $i0.02 per MMBtu. There are no specified minimums required, and to date, Sempra Infrastructure has not been required to deliver any natural gas pursuant to this agreement.
ENVIRONMENTAL ISSUES
Our
operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a PRP under the federal Superfund laws and similar state laws.
In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide
emissions could result in requirements for additional pollution control equipment or significant
emissions fees or taxes that could adversely affect Sempra Infrastructure. SDG&E’s and SoCalGas’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates.
We disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions,
exclusive of interest and costs, exceed the lesser of $i1 million or 1% of current assets, which was $i59
million for Sempra, $i16 million for SDG&E and $i21
million for SoCalGas at December 31, 2022.
We discuss environmental matters related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”
Other Environmental Issues
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 SDG&E and SoCalGas, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.
The environmental issues currently facing us, except for those related to the Leak as we discuss above or resolved during the last three years, include (1) investigation and remediation of SDG&E’s and SoCalGas’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by SDG&E and SoCalGas at which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.
i
The
table below shows the status at December 31, 2022 of SDG&E’s and SoCalGas’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:
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.
The following table shows our accrued liabilities for environmental
matters at December 31, 2022. Of the total liability, $ii14/
million at SoCalGas is recorded on a discounted basis, with a weighted-average discount rate of ii0.4/%.
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—
$
i5
$
i11
$
i16
SoCalGas(4)
i38
i3
i1
i42
Other
i—
i1
i—
i1
Total
Sempra(3)(4)
$
i38
$
i9
$
i12
$
i59
(1) Sites
for which we have been identified as a PRP.
(2) Includes $i5, $i1 and $i4
classified as current liabilities and $i54, $i15 and $i38
classified as noncurrent liabilities on Sempra’s, SDG&E’s and SoCalGas’ Consolidated Balance Sheets, respectively.
(3) Does not include SDG&E’s liability for SONGS marine environment mitigation.
(4) Does not include SoCalGas’ liability for environmental matters for the Leak. We discuss matters related to the Leak above in “Legal Proceedings – SoCalGas – Aliso Canyon Natural Gas Storage Facility Gas Leak.”
/
We expect future payments related to our environmental liabilities on an undiscounted basis to be $i5
million in 2023, $i11 million in 2024, $i10
million in 2025, $i1 million in 2026, $i17
million in 2027 and $i15 million thereafter.
In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the California Coastal Commission 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 $i144 million, of which $i54 million has been incurred through December 31,
2022 and $i90 million is accrued for remaining costs through 2059, which is recoverable in rates and included in noncurrent Regulatory Assets on Sempra’s and SDG&E’s Consolidated Balance Sheets.
NOTE
17. iSEGMENT INFORMATION
i
We have ifour
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.
▪Sempra Infrastructure includes the operating companies of our subsidiary, SI Partners, as well as a holding company and certain services
companies. Sempra Infrastructure develops, builds, operates and invests in energy infrastructure to help enable the energy transition in North American markets and globally. Sempra Infrastructure owns a i70% interest in SI Partners, which held a i100%
ownership interest in Sempra LNG Holding, LP and a i99.9% ownership interest in IEnova at December 31, 2022.
As we discuss in Note 5, the financial information related to our businesses that constituted the Sempra South American Utilities segment is presented as discontinued operations for all periods presented. The information in the tables below excludes amounts from discontinued operations unless otherwise noted. We completed the sales of our discontinued operations in the
second quarter of 2020.
We evaluate each segment’s performance based on its contribution to Sempra’s reported earnings and cash flows. SDG&E and SoCalGas operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC and, in the case of SDG&E, the FERC. We describe the accounting policies of all of our segments in Note 1.
The
cost of common services shared by the business segments is assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.
i
The following tables show selected information by segment from our Consolidated Statements of Operations and Consolidated Balance Sheets. We provide information about our equity method investments
by segment in Note 6. Amounts labeled as “All other” in the following tables consist primarily of activities of parent organizations and include certain nominal amounts from our South American businesses that did not qualify for treatment as discontinued operations.
(1)Revenues
for reportable segments include intersegment revenues of $i15, $i100, and $i43
for 2022; $i10, $i98, and $i55
for 2021; and $i5, $i88, and $(i3)
for 2020 for SDG&E, SoCalGas, and Sempra Infrastructure, respectively.
(2)Includes net PP&E and investments.
(3)Amounts are based on where the revenue originated, after intercompany eliminations.
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 consolidated financial statements of Sempra, except that Sempra Energy accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information. This financial information should be read in conjunction with Sempra’s consolidated financial statements and the accompanying notes thereto included in this Form 10-K.
Sempra Energy received cash dividends from its subsidiaries totaling $i832
million, $i375 million and $i300 million in 2022, 2021 and 2020, respectively.
NOTE
2. NEW ACCOUNTING STANDARDS
We describe in Note 2 of the Notes to Consolidated Financial Statements recent pronouncements that have had or may have a significant effect on Sempra Energy’s results of operations, financial condition, cash flows or disclosures.
NOTE
3. DEBT AND CREDIT FACILITY
SHORT-TERM DEBT
Committed Line of Credit
At December 31, 2022, Sempra Energy had capacity of $i4.0 billion under a committed line of credit with available unused credit of $i3.5 billion,
which provides liquidity and supports its commercial paper program.
The principal terms of Sempra Energy’s committed line of credit include the following:
▪The facility has a syndicate of i23 lenders. No single lender has greater than a i6%
share in the facility.
▪The facility provides for the issuance of $i200 million of letters of credit. Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, Sempra Energy has the right to increase its letter of credit commitment to up to $i500 million.
iNo letters of credit were outstanding at December 31, 2022.
▪Borrowings bear interest at a benchmark rate plus a margin that varies with Sempra Energy’s credit rating.
▪Sempra Energy must maintain a ratio of indebtedness to total capitalization (as defined in its credit facility) of no more than i65%
at the end of each quarter. At December 31, 2022, Sempra Energy was in compliance with this ratio under its credit facility.
i4.125%
Junior Subordinated Notes April 1, 2052(1)
i1,000
i1,000
i5.75%
Junior Subordinated Notes July 1, 2079(1)
i758
i758
i7,308
i6,058
Unamortized
discount on long-term debt
(i28)
(i37)
Unamortized
debt issuance costs
(i65)
(i52)
Total
long-term debt
$
i7,215
$
i5,969
(1) Callable
long-term debt not subject to make-whole provisions.
In March 2022, we issued $i750 million aggregate principal amount of i3.30%
senior unsecured notes due in full upon maturity on April 1, 2025 and received proceeds of $i745 million (net of debt discount, underwriting discounts and debt issuance costs of $i5
million), and $i500 million of i3.70% senior unsecured notes due in full upon maturity on April 1, 2029 and received proceeds of $i494
million (net of debt discount, underwriting discounts and debt issuance costs of $i6 million). Each series of the notes is redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions. We used the net proceeds for general corporate purposes and repayment of commercial paper.
At December 31, 2022, Sempra Energy had long-term debt maturities of $i750 million
in 2025, $i750 million in 2027 and $i5.8 billion
thereafter.
Additional information on Sempra Energy’s short-term and long-term debt is provided in Note 7 of the Notes to Consolidated Financial Statements.
NOTE 4. COMMITMENTS AND CONTINGENCIES
Sempra Energy has an
operating lease commitment related to its corporate headquarters building of approximately $i241 million. Sempra Energy expects payments for its operating lease to be $ii12/
million in each of 2023 and 2024, $iii13// million
in each of 2025 through 2027 and $i178 million thereafter.
For other contingencies and guarantees related to Sempra Energy, refer to Notes 6 and 16 of the Notes to Consolidated Financial Statements.
2022 Form 10-K | S-7
Dates Referenced Herein and Documents Incorporated by Reference
