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  4. [10-Q] SEMPRA Quarterly Earnings Report

[10-Q] SEMPRA Quarterly Earnings Report

Filing Impact
(Neutral)
Filing Sentiment
(Neutral)
Form Type
10-Q
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549 
FORM 10-Q
(Mark One)
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period endedSeptember 30, 2025
 or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period fromto

Commission File No.Exact Name of Registrant as Specified in its Charter,
Address of Principal Executive Office and Telephone Number		State of IncorporationIRS Employer Identification No.Former name, former address and former fiscal year, if changed since last report
1-14201SEMPRA
Sempra logo.jpg
California33-0732627No change
488 8th Avenue
San Diego, California 92101
(619) 696-2000
1-03779SAN DIEGO GAS & ELECTRIC COMPANY
SDGE_tm_rgb_c_v12-19.jpg
California95-1184800No change
8330 Century Park Court
San Diego, California 92123
(619) 696-2000
1-01402SOUTHERN CALIFORNIA GAS COMPANY
SoCalGas.jpg
California95-1240705No change
555 West 5th Street
Los Angeles, California 90013
(213) 244-1200
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of Each ClassTrading SymbolName of Each Exchange on Which Registered
SEMPRA:
Common Stock, without par valueSRE
New York Stock Exchange
5.75% Junior Subordinated Notes Due 2079, $25 par valueSREANew York Stock Exchange
SAN DIEGO GAS & ELECTRIC COMPANY:
None
SOUTHERN CALIFORNIA GAS COMPANY:
None



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.
Yes
☒
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).
Yes
☒
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:
☒ Large Accelerated Filer
☐ Accelerated Filer
☐ Non-accelerated Filer
☐ Smaller Reporting Company
☐ Emerging Growth Company
San Diego Gas & Electric Company:
☐ Large Accelerated Filer
☐ Accelerated Filer
☒ Non-accelerated Filer
☐ Smaller Reporting Company
☐ Emerging Growth Company
Southern California Gas Company:
☐ Large Accelerated Filer
☐ Accelerated Filer
☒ Non-accelerated Filer
☐ Smaller Reporting Company
☐ Emerging Growth Company
If an emerging growth company, indicate by check mark if the Registrants have 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.
☐
Indicate by check mark whether the Registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
☐
No
☒
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.
Common stock outstanding as of October 31, 2025:
Sempra
652,681,521 shares
San Diego Gas & Electric CompanyWholly owned by Enova Corporation, which is wholly owned by Sempra
Southern California Gas CompanyWholly owned by Pacific Enterprises, which is wholly owned by Sempra
2
Table of Contents
TABLE OF CONTENTS
 Page
Glossary
4
Information Regarding Forward-Looking Statements
7
  
PART I – FINANCIAL INFORMATION 
Item 1.
Financial Statements
9
Notes to Condensed Consolidated Financial Statements
Note 1. General Information and Other Financial Data
29
Note 2. New Accounting Standards
48
Note 3. Revenues
49
Note 4. Regulatory Matters
53
Note 5. Sempra – Investments in Unconsolidated Entities
56
Note 6. Sempra – Potential Divestitures
58
Note 7. Debt and Credit Facilities
61
Note 8. Derivative Financial Instruments
64
Note 9. Fair Value Measurements
71
Note 10. Sempra – Contingently Redeemable Noncontrolling Interest
78
Note 11. Sempra – Equity and Earnings Per Common Share
79
Note 12. San Onofre Nuclear Generating Station
82
Note 13. Commitments, Contingencies and Guarantees
84
Note 14. Segment Information
89
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
96
Overview
96
Results of Operations by Registrant
97
Capital Resources and Liquidity
117
Critical Accounting Estimates
134
New Accounting Standards
134
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
134
Item 4.
Controls and Procedures
136
  
PART II – OTHER INFORMATION 
Item 1.
Legal Proceedings
137
Item 1A.
Risk Factors
137
Item 5.
Other Information
139
Item 6.
Exhibits
140
  
Signatures
142
This combined Form 10-Q is separately filed by Sempra, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any one of these individual Registrants is filed by such entity on its own behalf. Each such Registrant 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 Registrant. No one section of the report deals with all aspects of the subject matter. A separate Part I – Item 1 is provided for each Registrant, except for the Notes to Condensed Consolidated Financial Statements, which are combined for all the Registrants. All Items other than Part I – Item 1 are combined for the three Registrants.
None of the website references in this report are active hyperlinks, and the information contained on or that can be accessed through any such website is not and shall not be deemed to be part of or incorporated by reference in this report or any other document that we file with or furnish to the SEC.

3
Table of Contents
The following terms and abbreviations appearing in this report have the meanings indicated below.
GLOSSARY
ABCalifornia Assembly Bill
ADIABlack Silverback ZC 2022 LP (assignee of Black River B 2017 Inc.), a wholly owned affiliate of Abu Dhabi Investment Authority
AFUDCallowance for funds used during construction
amparoan extraordinary constitutional appeal governed by Articles 103 and 107 of the Mexican Constitution and filed in Mexican federal court
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2024
AOCIaccumulated other comprehensive income (loss)
AROasset retirement obligation
ASCAccounting Standards Codification
ASEAAgencia de Seguridad, Energía y Ambiente (Mexico’s National Agency for Safety, Energy, and Environment)
ASUAccounting Standards Update
ATMat-the-market equity offering program pursuant to the Sales Agreement
Bcfbillion cubic feet
BechtelBechtel Energy Inc.
BlackstoneBX Frontier Member I LLC and BX Frontier Member II LLC, collectively
bpsbasis points
California ISO adderan additional 0.50% ROE for participation in the California ISO
Cameron LNG JVCameron LNG Holdings, LLC
Cameron LNG Phase 1 facilityCameron LNG JV liquefaction facility
Cameron LNG Phase 2 projectCameron LNG JV liquefaction expansion project
CCACommunity Choice Aggregator
CCMcost of capital adjustment mechanism
CFEComisión Federal de Electricidad (Mexico’s Federal Electricity Commission)
CFINCameron LNG FINCO, LLC, a wholly owned and unconsolidated affiliate of Cameron LNG JV
CNEComisión Nacional de Energía (Mexico’s National Commission of Energy), successor to Comisión Reguladora de Energía (Mexico’s Energy Regulatory Commission or CRE)
CODMchief operating decision maker as defined in Accounting Standards Codification 280
ConocoPhillipsConocoPhillips Company
Continuation Accountthe Wildfire Fund Continuation Account established by the 2025 Wildfire Legislation
COVID-19coronavirus disease 2019
CPUCCalifornia Public Utilities Commission
CRNCIcontingently redeemable noncontrolling interest
CRRcongestion revenue right
DOEU.S. Department of Energy
ECA LNGECA LNG Phase 1 and ECA LNG Phase 2, collectively
ECA LNG Phase 1ECA LNG Holdings B.V.
ECA LNG Phase 2ECA LNG II Holdings B.V.
ECA Regas FacilityEnergía Costa Azul, S. de R.L. de C.V. LNG regasification facility
EcogasEcogas México, S. de R.L. de C.V.
EdisonSouthern California Edison Company, a subsidiary of Edison International
EPCengineering, procurement and construction
EPSearnings per common share
ESLMexico’s Electric Sector Law
ETReffective income tax rate
Exchange ActSecurities Exchange Act of 1934, as amended
FDfinal decision
feed gasnatural gas that is provided to be used for processing to produce LNG
FERCFederal Energy Regulatory Commission
FIDfinal investment decision
FitchFitch Ratings, Inc.
FTAFree Trade Agreement
GCIMGas Cost Incentive Mechanism
GHGgreenhouse gas
GRCGeneral Rate Case
HOAHeads of Agreement
4
Table of Contents
GLOSSARY
HSLMexico’s Hydrocarbons Sector Law
IEnovaInfraestructura Energética Nova, S.A.P.I. de C.V.
IMGInfraestructura Marina del Golfo
IOUinvestor-owned utility
IRSU.S. Internal Revenue Service
ISOIndependent System Operator
ITCinvestment tax credit
JVjoint venture
KKR DenaliKKR Denali Holdco LLC, an affiliate of Kohlberg Kravis Roberts & Co. L.P.
KKR Partnersaffiliates of Kohlberg Kravis Roberts & Co. L.P. and indirect co-investor Canada Pension Plan Investment Board, collectively
KKR PinnacleKKR Pinnacle Investor L.P., an affiliate of Kohlberg Kravis Roberts & Co. L.P.
LA Firesthe wildfires in Los Angeles County, California, including the Palisades, Eaton and other fires, that burned in January and February of 2025
Leakthe leak at the SoCalGas Aliso Canyon natural gas storage facility injection-and-withdrawal well, SS25, discovered by SoCalGas on October 23, 2015
LHMexico’s Hydrocarbons Law
LIEMexico’s Electricity Industry Law
LNGliquefied natural gas
MD&AManagement’s Discussion and Analysis of Financial Condition and Results of Operations
MMBtumillion British thermal units (of natural gas)
Moody’sMoody’s Investors Service, Inc.
MOUMemorandum of Understanding
Mtpamillion tonnes per annum
MWmegawatt
MWhmegawatt hour
NCInoncontrolling interest(s)
NDTnuclear decommissioning trusts
O&Moperation and maintenance expense
OBBBAOne Big Beautiful Bill Act of 2025
OCIother comprehensive income (loss)
OEISOffice of Energy Infrastructure Safety
OncorOncor Electric Delivery Company LLC
Oncor HoldingsOncor Electric Delivery Holdings Company LLC
OSHAOccupational Safety and Health Administration
Other SempraAll Sempra consolidated entities, except for SDG&E and SoCalGas
PA2 JVCoa subsidiary of SI Partners that owns Port Arthur LNG II
PA2 JVCo LLCAPA2 JVCo’s limited liability company agreement
PA LNG Phase 1 projectinitial phase of the Port Arthur LNG liquefaction project
PA LNG Phase 2 projectsecond phase of the Port Arthur LNG liquefaction project
PBOPpostretirement benefits other than pension
PEMEXPetróleos Mexicanos (Mexican state-owned oil company)
PG&EPacific Gas & Electric Company
Port Arthur LNG IPort Arthur LNG, LLC, a subsidiary of SI Partners that owns the PA LNG Phase 1 project
Port Arthur LNG IIPort Arthur LNG Phase II, LLC, a subsidiary of SI Partners that owns the PA LNG Phase 2 project
PP&Eproperty, plant and equipment
PPApower purchase agreement
PSEPPipeline Safety Enhancement Plan
PUCTPublic Utility Commission of Texas
Registrantshas the meaning set forth in Rule 12b-2 under the Exchange Act and consists of Sempra, SDG&E and SoCalGas for purposes of this report
ROEreturn on equity
RSUrestricted stock unit
S&PS&P Global Ratings, a division of S&P Global Inc.
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GLOSSARY
Sales AgreementATM Equity Offering Sales Agreement, dated November 6, 2024, among Sempra and Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, Morgan Stanley & Co. LLC, MUFG Securities Americas Inc., RBC Capital Markets, LLC, Scotia Capital (USA) Inc., and Wells Fargo Securities, LLC (each a sales agent or forward seller) and Barclays Bank PLC, Bank of America, N.A., Citibank, N.A., Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, Morgan Stanley & Co. LLC, MUFG Securities EMEA plc, Royal Bank of Canada, The Bank of Nova Scotia and Wells Fargo Bank, National Association, or one of their respective affiliates (each a forward purchaser)
SDG&ESan Diego Gas & Electric Company
SDSRASenior Debt Service Reserve Account
SECU.S. Securities and Exchange Commission
SEDATUSecretaría de Desarrollo Agrario, Territorial y Urbano (Mexico’s agency in charge of agriculture, land and urban development)
SENERSecretaría de Energía de México (Mexico’s Ministry of Energy)
series C preferred stockSempra’s 4.875% fixed-rate reset cumulative redeemable perpetual preferred stock, series C
Sharyland UtilitiesSharyland Utilities, L.L.C.
SI PartnersSempra Infrastructure Partners, LP, the holding company for most of Sempra’s subsidiaries not subject to California or Texas utility regulation, and, unless otherwise stated or indicated by the context, its consolidated subsidiaries
SoCalGasSouthern California Gas Company
SOFRSecured Overnight Financing Rate
SONGSSan Onofre Nuclear Generating Station
SPAsale and purchase agreement
SRPsystem resiliency plan
Support Agreementsupport agreement, dated July 28, 2020 and amended in June 2021, January 2025 and March 2025, between Sempra and Sumitomo Mitsui Banking Corporation
TAG NorteTAG Norte Holding, S. de R.L. de C.V.
TCEQTexas Commission on Environmental Quality
TCJATax Cuts and Jobs Act of 2017
TdMTermoeléctrica de Mexicali
TO5Electric Transmission Owner Formula Rate, effective June 1, 2019
TO5 adder refund provisionthe provision in the TO5 settlement providing that SDG&E will refund the California ISO adder as of June 1, 2019 if the FERC issues an order ruling that California IOUs are no longer eligible for the California ISO adder
TO6Electric Transmission Owner Formula Rate, effective June 1, 2025, subject to refund
U.S. GAAPgenerally accepted accounting principles in the United States of America
UTMunified tracker mechanism
VIEvariable interest entity
VREPVoluntary Retirement Enhancement Program
Wildfire Fundthe fund established pursuant to AB 1054
2019 Wildfire LegislationAB 1054 and AB 111
2025 Wildfire LegislationSenate Bill 254
In this report, references to “Sempra” are to Sempra and its consolidated entities, collectively, and references to “we,” “our,” “us” and “our company” are to the applicable Registrant and its consolidated entities, collectively, in each case 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 Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements when discussed together or collectively:
▪the Condensed Consolidated Financial Statements and related Notes of Sempra;
▪the Condensed Financial Statements and related Notes of SDG&E; and
▪the Condensed Financial Statements and related Notes of SoCalGas.
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based on assumptions about 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 “believe,” “expect,” “intend,” “anticipate,” “contemplate,” “plan,” “estimate,” “project,” “forecast,” “envision,” “should,” “could,” “would,” “will,” “confident,” “may,” “can,” “potential,” “possible,” “proposed,” “in process,” “construct,” “develop,” “opportunity,” “preliminary,” “pro forma,” “strategic,” “initiative,” “target,” “outlook,” “optimistic,” “poised,” “positioned,” “maintain,” “continue,” “progress,” “advance,” “goal,” “aim,” “commit,” or similar expressions, or when we discuss our guidance, priorities, strategies, goals, vision, mission, 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:
▪California wildfires, including potential liability for damages regardless of fault and any inability to recover all or a substantial portion of costs from insurance, the Wildfire Fund and the Continuation Account, rates from customers or a combination thereof
▪decisions, denials of cost recovery, audits, investigations, inquiries, ordered studies, regulations, denials or revocations of permits, consents, approvals or other authorizations, renewals of franchises, and other actions, including the failure to honor contracts and commitments, by the (i) CPUC, CNE, DOE, FERC, IRS, PUCT and other regulatory bodies and (ii) U.S., Mexico and states, counties, cities and other jurisdictions therein and in other countries where we do business
▪the success of business development efforts, construction projects, acquisitions, divestitures, and other significant transactions such as the planned sale of a portion of our equity interest in SI Partners, including risks related to, as applicable, (i) being able to reach FID, (ii) negotiating pricing and other terms in definitive contracts, (iii) completing construction projects or other transactions on schedule and budget, (iv) realizing anticipated benefits from any of these efforts if completed, (v) obtaining regulatory and other approvals and (vi) third parties honoring their contracts and commitments, including with respect to closing or post-closing payments
▪changes to our capital expenditure plans and their potential impact on rate base or other growth
▪changes, due to evolving economic, political and other factors, to (i) trade and other foreign policy, including the imposition of tariffs by the U.S. and foreign countries, and (ii) laws and regulations, including those related to tax and the energy industry in the U.S. and Mexico
▪litigation, arbitration, property disputes and other proceedings
▪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
▪the availability, uses, sufficiency, and cost of capital resources and our ability to borrow money or otherwise raise capital on favorable terms and meet our obligations, which can be affected by, among other things, (i) actions by credit rating agencies to downgrade our credit ratings or place those ratings on negative outlook, (ii) instability in the capital markets, and (iii) fluctuating interest rates and inflation
▪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 customers due to (i) volatility in inflation, interest rates and commodity prices and the imposition of tariffs, (ii) with respect to SDG&E’s and SoCalGas’ businesses, the cost of meeting the demand for lower carbon and reliable energy in California, and (iii) with respect to Sempra Infrastructure’s business, volatility in foreign currency exchange rates
▪the impact of climate policies, laws, rules, regulations, trends and required disclosures, including actions to reduce or eliminate reliance on natural gas, increased uncertainty in the political or regulatory environment for California natural gas distribution companies, the risk of nonrecovery for stranded assets, and uncertainty related to emerging technologies
▪weather, natural disasters, pandemics, accidents, equipment failures, explosions, terrorism, information system outages or other events, such as work stoppages, that disrupt our operations, damage our facilities or systems, cause the release of harmful materials or fires or subject us to liability for damages, fines and penalties, some of which may not be recoverable through regulatory mechanisms or insurance or may impact our ability to obtain satisfactory levels of affordable insurance
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▪the availability of electric power, natural gas and natural gas storage and transportation capacity, including disruptions caused by failures in the transmission grid or pipeline and storage systems or limitations on the injection and withdrawal of natural gas from storage facilities
▪Oncor’s ability to reduce or eliminate its quarterly dividends due to regulatory and governance requirements and commitments, including by actions of Oncor’s independent directors or a minority member director
▪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, in our Annual Report and in other reports we file with the SEC.
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PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

SEMPRA
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts; shares in thousands)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
 (unaudited)
REVENUES 
Utilities:
Natural gas$1,363 $1,195 $5,195 $4,798 
Electric1,260 1,069 3,350 3,269 
Energy-related businesses528 512 1,408 1,360 
Total revenues3,151 2,776 9,953 9,427 
EXPENSES AND OTHER INCOME 
Utilities: 
Cost of natural gas(210)(99)(886)(790)
Cost of electric fuel and purchased power(122)18 (265)(227)
Energy-related businesses cost of sales(117)(134)(321)(297)
Operation and maintenance(1,349)(1,326)(3,931)(3,871)
Depreciation and amortization(662)(614)(1,955)(1,811)
Franchise fees and other taxes(194)(175)(555)(515)
Other income, net49 65 199 194 
Interest income17 17 65 47 
Interest expense(403)(328)(1,195)(944)
Income before income taxes and equity earnings160 200 1,109 1,213 
Income tax (expense) benefit(482)105 (711)63 
Equity earnings472 454 1,190 1,235 
Net income150 759 1,588 2,511 
Earnings attributable to noncontrolling interests(55)(110)(103)(325)
Preferred deemed dividends(11)— (11)— 
Preferred dividends(7)(11)(29)(33)
Preferred dividends of subsidiary— — (1)(1)
Earnings attributable to common shares$77 $638 $1,444 $2,152 
Basic EPS:
Earnings
$0.12 $1.01 $2.21 $3.40 
Weighted-average common shares outstanding652,948 633,752 652,538 633,342 
Diluted EPS:
Earnings
$0.12 $1.00 $2.21 $3.38 
Weighted-average common shares outstanding654,009 638,061 653,420 636,566 
See Notes to Condensed Consolidated Financial Statements.
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SEMPRA
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Sempra shareholders’ equity
Pretax
amount		Income tax
(expense) benefit		Net-of-tax
amount		Noncontrolling
interests
(after tax)		Total
(unaudited)
 Three months ended September 30, 2025 and 2024
2025:     
Net income$577 $(482)$95 $55 $150 
Other comprehensive income (loss):     
Foreign currency translation adjustments5 — 5 3 8 
Financial instruments(14)1 (13)(1)(14)
Pension and other postretirement benefits12 (1)11 — 11 
Total other comprehensive income3 — 3 2 5 
Comprehensive income $580 $(482)$98 $57 $155 
2024:     
Net income$544 $105 $649 $110 $759 
Other comprehensive income (loss):    
Foreign currency translation adjustments(12)— (12)(5)(17)
Financial instruments(74)20 (54)(171)(225)
Pension and other postretirement benefits3 (1)2 — 2 
Total other comprehensive loss(83)19 (64)(176)(240)
Comprehensive income (loss)$461 $124 $585 $(66)$519 
 Nine months ended September 30, 2025 and 2024
2025:     
Net income$2,196 $(711)$1,485 $103 $1,588 
Other comprehensive income (loss):     
Foreign currency translation adjustments16 — 16 8 24 
Financial instruments(86)8 (78)(13)(91)
Pension and other postretirement benefits18 (2)16 — 16 
Total other comprehensive loss(52)6 (46)(5)(51)
Comprehensive income2,144 (705)1,439 98 1,537 
Preferred dividends of subsidiary(1)— (1)— (1)
Comprehensive income, after preferred
dividends of subsidiary
$2,143 $(705)$1,438 $98 $1,536 
2024:    
Net income$2,123 $63 $2,186 $325 $2,511 
Other comprehensive income (loss):     
Foreign currency translation adjustments(25)— (25)(11)(36)
Financial instruments(26)4 (22)(2)(24)
Pension and other postretirement benefits16 (4)12 — 12 
Total other comprehensive loss(35)— (35)(13)(48)
Comprehensive income2,088 63 2,151 312 2,463 
Preferred dividends of subsidiary(1)— (1)— (1)
Comprehensive income, after preferred
dividends of subsidiary
$2,087 $63 $2,150 $312 $2,462 
See Notes to Condensed Consolidated Financial Statements.
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SEMPRA
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
September 30,December 31,
 2025
2024(1)
 (unaudited)
ASSETS 
Current assets: 
Cash and cash equivalents$5 $1,565 
Restricted cash2 21 
Accounts receivable – trade, net1,409 1,983 
Accounts receivable – other, net200 397 
Due from unconsolidated affiliates— 13 
Income taxes receivable79 90 
Inventories565 559 
Prepaid expenses247 255 
Regulatory assets500 60 
Fixed-price contracts and other derivatives35 91 
Greenhouse gas allowances200 217 
Assets held for sale28,465 — 
Other current assets19 34 
Total current assets31,726 5,285 
Other assets: 
Restricted cash— 3 
Regulatory assets4,298 3,937 
Greenhouse gas allowances1,237 845 
Nuclear decommissioning trusts897 875 
Dedicated assets in support of certain benefit plans585 585 
Deferred income taxes19 172 
Right-of-use assets – operating leases1,219 1,177 
Investment in Oncor Holdings17,038 15,400 
Other investments144 2,534 
Goodwill— 1,602 
Other intangible assets— 292 
Wildfire fund250 262 
Other long-term assets1,155 1,749 
Total other assets26,842 29,433 
Property, plant and equipment: 
Property, plant and equipment65,951 80,397 
Less accumulated depreciation and amortization(17,600)(18,960)
Property, plant and equipment, net48,351 61,437 
Total assets$106,919 $96,155 
(1)    Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.
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SEMPRA
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
September 30,December 31,
 2025
2024(1)
 (unaudited)
LIABILITIES, CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST, AND EQUITY 
Current liabilities: 
Short-term debt$1,833 $2,016 
Accounts payable – trade1,301 2,238 
Accounts payable – other219 208 
Due to unconsolidated affiliates17 — 
Dividends and interest payable910 773 
Accrued compensation and benefits486 558 
Regulatory liabilities4 141 
Mandatorily redeemable preferred stock900 — 
Current portion of long-term debt and finance leases1,875 2,274 
Greenhouse gas obligations200 217 
Liabilities held for sale11,175 — 
Other current liabilities1,068 1,251 
Total current liabilities19,988 9,676 
Long-term debt and finance leases28,985 31,558 
Deferred credits and other liabilities: 
Due to unconsolidated affiliates — 352 
Regulatory liabilities 4,027 3,817 
Greenhouse gas obligations947 506 
Pension and other postretirement benefit plan obligations, net of plan assets127 168 
Deferred income taxes6,105 5,845 
Asset retirement obligations3,781 3,737 
Deferred credits and other2,740 2,708 
Total deferred credits and other liabilities17,727 17,133 
Commitments and contingencies (Note 13)
Contingently redeemable noncontrolling interest1,933 — 
Equity: 
Preferred stock (50,000,000 shares authorized; 900,000 shares of series C outstanding at
December 31, 2024)
— 889 
Common stock (1,125,000,000 shares authorized; 652,525,871 and 650,629,876 shares
outstanding at September 30, 2025 and December 31, 2024, respectively; no par value)
14,203 13,520 
Retained earnings17,161 16,979 
Accumulated other comprehensive income (loss)(212)(166)
Total Sempra shareholders’ equity31,152 31,222 
Preferred stock of subsidiary20 20 
Other noncontrolling interests7,114 6,546 
Total equity38,286 37,788 
Total liabilities, contingently redeemable noncontrolling interest, and equity$106,919 $96,155 
(1)    Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.
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SEMPRA
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Nine months ended September 30,
 20252024
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income $1,588 $2,511 
Adjustments to reconcile net income to net cash provided by operating activities:  
Depreciation and amortization1,955 1,811 
Deferred income taxes and investment tax credits558 (223)
Equity earnings(1,190)(1,235)
Share-based compensation expense25 63 
Fixed-price contracts and other derivatives133 11 
Bad debt expense109 149 
Other3 7 
Net change in working capital components(745)55 
Distributions from investments828 654 
Changes in other noncurrent assets and liabilities, net112 (261)
Net cash provided by operating activities3,376 3,542 
CASH FLOWS FROM INVESTING ACTIVITIES  
Expenditures for property, plant and equipment(7,201)(5,765)
Expenditures for investments (1,492)(588)
Purchases of nuclear decommissioning and other trust assets(746)(658)
Proceeds from sales of nuclear decommissioning and other trust assets831 704 
Other3 11 
Net cash used in investing activities(8,605)(6,296)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid(1,195)(1,121)
Preferred dividends paid(22)(22)
Issuances of common stock26 26 
Repurchases of common stock(58)(41)
Issuances of debt (maturities greater than 90 days)8,892 6,437 
Payments on debt (maturities greater than 90 days) and finance leases (4,142)(2,216)
Decrease in short-term debt, net(170)(929)
Advances from unconsolidated affiliates 96 85 
Contributions from contingently redeemable noncontrolling interest, net of transaction costs3,212 — 
Proceeds from investor equity subscription106 — 
Contributions from noncontrolling interests137 1,121 
Distributions to noncontrolling interests(131)(235)
Other(90)(39)
Net cash provided by financing activities6,661 3,066 
Effect of exchange rate changes on cash, cash equivalents and restricted cash4 (11)
Increase in cash, cash equivalents and restricted cash1,436 301 
Cash, cash equivalents and restricted cash, January 11,589 389 
Cash, cash equivalents and restricted cash, September 30$3,025 $690 
See Notes to Condensed Consolidated Financial Statements.
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SEMPRA
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
 Nine months ended September 30,
 20252024
 (unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION  
Interest payments, net of amounts capitalized$940 $814 
Income tax payments, net of refunds339272 
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES  
Accrued interest receivable capitalized to note receivable$13 $13 
Repayments of advances from unconsolidated affiliate in lieu of distributions45 62 
Accrued capital expenditures for PP&E1,619 1,059 
Increase (decrease) in ARO capitalized to PP&E59 (9)
Increase in finance lease obligations capitalized to PP&E41 27 
Unamortized debt issuance costs reclassified from noncurrent asset to long-term debt49 2 
Redemption of preferred stock900 — 
Preferred deemed dividends(11)— 
Preferred dividends declared but not paid18 22 
Common dividends declared but not paid421 392 
Common dividends issued in stock39 40 
See Notes to Condensed Consolidated Financial Statements.
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SEMPRA
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST
(Dollars in millions)
 CRNCIPreferred stockCommon stockRetained earningsAOCISempra
shareholders'
equity		NCITotal
equity
(unaudited)
Three months ended September 30, 2025
Balance at June 30, 2025$— $889 $13,518 $17,505 $(215)$31,697 $6,599 $38,296 
Net income95 95 55 150 
Other comprehensive income3 3 2 5 
Share-based compensation expense14 14 14 
Dividends declared:
Series C preferred stock ($12.19/share)
(7)(7)(7)
Common stock ($0.65/share)
(421)(421)(421)
Redemption of preferred stock(900)(900)(900)
Preferred deemed dividends11 (11)— — 
Issuances of common stock20 20 20 
CRNCI and NCI activities:
Contributions from CRNCI3,166 
Investor equity subscription76 16 16 9 25 
Allocation of interests(1,309)635 635 455 1,090 
Contributions from NCI54 54 
Distributions to NCI(40)(40)
Balance at September 30, 2025$1,933 $— $14,203 $17,161 $(212)$31,152 $7,134 $38,286 
 Three months ended September 30, 2024
Balance at June 30, 2024$889 $12,250 $16,461 $(121)$29,479 $5,940 $35,419 
Net income649 649 110 759 
Other comprehensive loss(64)(64)(176)(240)
Share-based compensation expense22 22 22 
Dividends declared:
Series C preferred stock ($12.19/share)
(11)(11)(11)
Common stock ($0.62/share)
(392)(392)(392)
Issuances of common stock21 21 21 
Repurchases of common stock(1)(1)(1)
Noncontrolling interest activities:
Contributions335 335 
Distributions(32)(32)
Balance at September 30, 2024$889 $12,292 $16,707 $(185)$29,703 $6,177 $35,880 
See Notes to Condensed Consolidated Financial Statements.
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SEMPRA
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST AND EQUITY
(Dollars in millions)
 CRNCIPreferred stockCommon stockRetained earningsAOCISempra
shareholders’
equity		NCITotal
equity
(unaudited)
Nine months ended September 30, 2025
Balance at December 31, 2024$— $889 $13,520 $16,979 $(166)$31,222 $6,566 $37,788 
Net income1,485 1,485 103 1,588 
Other comprehensive loss(46)(46)(5)(51)
Share-based compensation expense25 25 25 
Dividends declared:
Series C preferred stock ($36.57/share)
(29)(29)(29)
Common stock ($1.94/share)
(1,262)(1,262)(1,262)
Redemption of preferred stock(900)(900)(900)
Preferred deemed dividends11 (11)— — 
Preferred dividends of subsidiary(1)(1)(1)
Issuances of common stock65 65 65 
Repurchases of common stock(58)(58)(58)
CRNCI and NCI activities:
Contributions from CRNCI3,166 
Investor equity subscription76 16 16 9 25 
Allocation of interests(1,309)635 635 455 1,090 
Contributions from NCI137 137 
Distributions to NCI(131)(131)
Balance at September 30, 2025$1,933 $— $14,203 $17,161 $(212)$31,152 $7,134 $38,286 
 Nine months ended September 30, 2024
Balance at December 31, 2023$889 $12,204 $15,732 $(150)$28,675 $4,979 $33,654 
Net income2,186 2,186 325 2,511 
Other comprehensive loss(35)(35)(13)(48)
Share-based compensation expense63 63 63 
Dividends declared:
Series C preferred stock ($36.57/share)
(33)(33)(33)
Common stock ($1.86/share)
(1,177)(1,177)(1,177)
Preferred dividends of subsidiary(1)(1)(1)
Issuances of common stock66 66 66 
Repurchases of common stock(41)(41)(41)
Noncontrolling interest activities:
Contributions1,121 1,121 
Distributions(235)(235)
Balance at September 30, 2024$889 $12,292 $16,707 $(185)$29,703 $6,177 $35,880 
See Notes to Condensed Consolidated Financial Statements.
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SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
 (unaudited)
Operating revenues:    
Electric$1,264 $1,073 $3,362 $3,282 
Natural gas216 170 800 695 
Total operating revenues1,480 1,243 4,162 3,977 
Operating expenses:    
Cost of electric fuel and purchased power135 (5)314 277 
Cost of natural gas44 38 175 177 
Operation and maintenance451 420 1,294 1,254 
Depreciation and amortization334 308 977 910 
Franchise fees and other taxes116 106 324 301 
Total operating expenses1,080 867 3,084 2,919 
Operating income400 376 1,078 1,058 
Other income, net32 30 103 86 
Interest income— 1 2 5 
Interest expense(141)(131)(415)(390)
Income before income taxes291 276 768 759 
Income tax benefit (expense)33 (15)12 (89)
Net income/Earnings attributable to common shares$324 $261 $780 $670 
See Notes to Condensed Financial Statements.
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SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Pretax
amount		Income tax
benefit (expense)		Net-of-tax
amount
 (unaudited)
 Three months ended September 30, 2025 and 2024
2025:   
Net income/Comprehensive income $291 $33 $324 
2024:   
Net income/Comprehensive income$276 $(15)$261 
 Nine months ended September 30, 2025 and 2024
2025:   
Net income/Comprehensive income$768 $12 $780 
2024:   
Net income/Comprehensive income$759 $(89)$670 
See Notes to Condensed Financial Statements.
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SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Dollars in millions)
September 30,December 31,
 2025
2024(1)
 (unaudited)
ASSETS 
Current assets: 
Accounts receivable – trade, net$849 $774 
Accounts receivable – other, net120 89 
Due from unconsolidated affiliates13 — 
Income taxes receivable, net33 27 
Inventories263 202 
Prepaid expenses156 139 
Regulatory assets213 16 
Greenhouse gas allowances26 27 
Other current assets28 27 
Total current assets1,701 1,301 
Other assets: 
Regulatory assets2,419 2,024 
Greenhouse gas allowances283 272 
Nuclear decommissioning trusts897 875 
Right-of-use assets – operating leases1,061 795 
Wildfire fund250 262 
Other long-term assets135 133 
Total other assets5,045 4,361 
Property, plant and equipment: 
Property, plant and equipment34,674 33,162 
Less accumulated depreciation and amortization(8,581)(8,051)
Property, plant and equipment, net 26,093 25,111 
Total assets$32,839 $30,773 
(1)    Derived from audited financial statements.
See Notes to Condensed Financial Statements.
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SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
 September 30,December 31,
2025
2024(1)
 (unaudited)
LIABILITIES AND SHAREHOLDER’S EQUITY 
Current liabilities: 
Short-term debt$27 $417 
Accounts payable811 742 
Due to unconsolidated affiliates65 59 
Interest payable138 84 
Accrued compensation and benefits165 175 
Accrued franchise fees71 54 
Regulatory liabilities3 75 
Current portion of long-term debt and finance leases 796 42 
Greenhouse gas obligations26 27 
Asset retirement obligations101 97 
Other current liabilities273 215 
Total current liabilities2,476 1,987 
Long-term debt and finance leases 10,086 10,018 
Deferred credits and other liabilities: 
Regulatory liabilities2,891 2,701 
Greenhouse gas obligations119 62 
Pension obligation, net of plan assets38 28 
Deferred income taxes3,376 3,211 
Asset retirement obligations793 803 
Deferred credits and other1,716 1,399 
Total deferred credits and other liabilities8,933 8,204 
Commitments and contingencies (Note 13)
Shareholder’s equity: 
Preferred stock (45,000,000 shares authorized; none issued)
— — 
Common stock (255,000,000 shares authorized; 116,583,358 shares outstanding;
no par value)
1,660 1,660 
Retained earnings9,696 8,916 
Accumulated other comprehensive income (loss)(12)(12)
Total shareholder’s equity11,344 10,564 
Total liabilities and shareholder's equity$32,839 $30,773 
(1)    Derived from audited financial statements.
See Notes to Condensed Financial Statements.
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SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Nine months ended September 30,
 20252024
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income$780 $670 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization977 910 
Deferred income taxes and investment tax credits(26)94 
Bad debt expense39 46 
Other(1)(19)
Net change in working capital components(321)(204)
Changes in noncurrent assets and liabilities, net(105)(54)
Net cash provided by operating activities1,343 1,443 
CASH FLOWS FROM INVESTING ACTIVITIES  
Expenditures for property, plant and equipment(1,811)(1,838)
Purchases of nuclear decommissioning trust assets(672)(605)
Proceeds from sales of nuclear decommissioning trust assets709 639 
Other12 11 
Net cash used in investing activities(1,762)(1,793)
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid— (225)
Issuances of debt (maturities greater than 90 days)848 594 
Payments on debt (maturities greater than 90 days) and finance leases(32)(432)
(Decrease) increase in short-term debt, net(390)384 
Debt issuance costs(7)(6)
Net cash provided by financing activities419 315 
Decrease in cash and cash equivalents— (35)
Cash and cash equivalents, January 1— 50 
Cash and cash equivalents, September 30$— $15 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION  
Interest payments, net of amounts capitalized$355 $348 
Income tax payments, net of refunds23 — 
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES  
Accrued capital expenditures for PP&E$206 $214 
Increase in finance lease obligations capitalized to PP&E8 8 
See Notes to Condensed Financial Statements.
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SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Dollars in millions)
 Common
stock		Retained
earnings		Accumulated
other
comprehensive
income (loss)		Total
shareholder’s
equity
(unaudited)
Three months ended September 30, 2025
Balance at June 30, 2025$1,660 $9,372 $(12)$11,020 
Net income324 324 
Balance at September 30, 2025$1,660 $9,696 $(12)$11,344 
Three months ended September 30, 2024
Balance at June 30, 2024$1,660 $8,659 $(8)$10,311 
Net income261 261 
Dividends declared:
Common stock ($1.93/share)
(225)(225)
Balance at September 30, 2024$1,660 $8,695 $(8)$10,347 
 Nine months ended September 30, 2025
Balance at December 31, 2024$1,660 $8,916 $(12)$10,564 
Net income780 780 
Balance at September 30, 2025$1,660 $9,696 $(12)$11,344 
Nine months ended September 30, 2024
Balance at December 31, 2023$1,660 $8,250 $(8)$9,902 
Net income670 670 
Dividends declared:
Common stock ($1.93/share)
(225)(225)
Balance at September 30, 2024$1,660 $8,695 $(8)$10,347 
See Notes to Condensed Financial Statements.
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SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
2025202420252024
 (unaudited)
Operating revenues$1,181 $1,054 $4,469 $4,168 
Operating expenses: 
Cost of natural gas182 82 749 661 
Operation and maintenance623 678 2,002 1,998 
Depreciation and amortization257 228 750 675 
Franchise fees and other taxes74 66 215 200 
Total operating expenses1,136 1,054 3,716 3,534 
Operating income45 — 753 634 
Other (expense) income, net(3)13 37 73 
Interest income2 3 5 7 
Interest expense(93)(82)(272)(237)
(Loss) income before income taxes(49)(66)523 477 
Income tax benefit (expense)95 52 51 (1)
Net income (loss)46 (14)574 476 
Preferred dividends— — (1)(1)
Earnings (losses) attributable to common shares$46 $(14)$573 $475 
See Notes to Condensed Financial Statements.
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SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Pretax
amount		Income tax
 benefit (expense) 		Net-of-tax
amount
 (unaudited)
 Three months ended September 30, 2025 and 2024
2025:   
Net (loss) income$(49)$95 $46 
Other comprehensive income (loss):
Financial instruments1 — 1 
Pension and other postretirement benefits7 (2)5 
Total other comprehensive income8 (2)6 
Comprehensive (loss) income$(41)$93 $52 
2024:   
Net loss/Comprehensive loss$(66)$52 $(14)
Nine months ended September 30, 2025 and 2024
2025:   
Net income$523 $51 $574 
Other comprehensive income (loss):
Financial instruments1 — 1 
Pension and other postretirement benefits10 (2)8 
Total other comprehensive income11 (2)9 
Comprehensive income$534 $49 $583 
2024:   
Net income$477 $(1)$476 
Other comprehensive income (loss):
Financial instruments1 — 1 
Pension and other postretirement benefits1 — 1 
Total other comprehensive income2 — 2 
Comprehensive income$479 $(1)$478 
See Notes to Condensed Financial Statements.
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SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS
(Dollars in millions)
 September 30,December 31,
2025
2024(1)
 (unaudited)
ASSETS 
Current assets: 
Cash and cash equivalents$— $12 
Accounts receivable – trade, net560 932 
Accounts receivable – other, net73 71 
Due from unconsolidated affiliates2 16 
Inventories302 287 
Regulatory assets287 42 
Greenhouse gas allowances174 176 
Other current assets115 71 
Total current assets1,513 1,607 
Other assets: 
Regulatory assets1,855 1,844 
Greenhouse gas allowances954 526 
Right-of-use assets – operating leases9 18 
Other long-term assets608 609 
Total other assets3,426 2,997 
Property, plant and equipment: 
Property, plant and equipment30,525 29,084 
Less accumulated depreciation and amortization(8,811)(8,330)
Property, plant and equipment, net21,714 20,754 
Total assets$26,653 $25,358 
(1)    Derived from audited financial statements.
See Notes to Condensed Financial Statements.
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SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
 September 30,December 31,
2025
2024(1)
 (unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY 
Current liabilities: 
Short-term debt$411 $1,037 
Accounts payable – trade488 752 
Accounts payable – other174 158 
Due to unconsolidated affiliates62 38 
Accrued compensation and benefits221 245 
Contributions in aid of construction172 117 
Regulatory liabilities1 64 
Current portion of long-term debt and finance leases530 373 
Greenhouse gas obligations174 176 
Asset retirement obligations82 91 
Other current liabilities436 334 
Total current liabilities2,751 3,385 
Long-term debt and finance leases7,622 7,031 
Deferred credits and other liabilities: 
Regulatory liabilities1,136 1,115 
Greenhouse gas obligations828 410 
Pension obligation, net of plan assets17 45 
Deferred income taxes2,193 2,005 
Asset retirement obligations2,986 2,839 
Deferred credits and other377 367 
Total deferred credits and other liabilities7,537 6,781 
Commitments and contingencies (Note 13)
Shareholders’ equity: 
Preferred stock (11,000,000 shares authorized; 862,043 shares outstanding)
22 22 
Common stock (100,000,000 shares authorized; 91,300,000 shares outstanding;
no par value)
2,316 2,316 
Retained earnings6,423 5,850 
Accumulated other comprehensive income (loss)(18)(27)
Total shareholders’ equity8,743 8,161 
Total liabilities and shareholders’ equity$26,653 $25,358 
(1)    Derived from audited financial statements.
See Notes to Condensed Financial Statements.
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SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Nine months ended September 30,
 20252024
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income$574 $476 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization750 675 
Deferred income taxes and investment tax credits(82)4 
Bad debt expense43 70 
Other(10)(21)
Net change in working capital components(110)321 
Changes in noncurrent assets and liabilities, net261 (155)
Net cash provided by operating activities1,426 1,370 
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment(1,523)(1,491)
Net cash used in investing activities(1,523)(1,491)
CASH FLOWS FROM FINANCING ACTIVITIES
Preferred dividends paid(1)(1)
Issuances of debt (maturities greater than 90 days)1,090 1,594 
Payments on debt (maturities greater than 90 days) and finance leases(1,069)(517)
Increase (decrease) in short-term debt, net74 (946)
Debt issuance costs(9)(9)
Net cash provided by financing activities85 121 
Decrease in cash and cash equivalents(12)— 
Cash and cash equivalents, January 112 2 
Cash and cash equivalents, September 30$— $2 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION  
Interest payments, net of amounts capitalized$222 $189 
Income tax payments, net of refunds58 — 
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES  
Accrued capital expenditures for PP&E$244 $265 
Increase in finance lease obligations capitalized to PP&E33 19 
Increase (decrease) in ARO capitalized to PP&E59 (9)
See Notes to Condensed Financial Statements.
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SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Dollars in millions)
 Preferred
stock		Common
stock		Retained
earnings		Accumulated
other
comprehensive
income (loss)		Total
shareholders’
equity
(unaudited)
Three months ended September 30, 2025
Balance at June 30, 2025$22 $2,316 $6,377 $(24)$8,691 
Net income46 46 
Other comprehensive income6 6 
Dividends declared:
Preferred stock ($0.38/share)
— — 
Balance at September 30, 2025$22 $2,316 $6,423 $(18)$8,743 
Three months ended September 30, 2024
Balance at June 30, 2024$22 $2,316 $5,584 $(21)$7,901 
Net loss(14)(14)
Dividends declared:
Preferred stock ($0.38/share)
— — 
Balance at September 30, 2024$22 $2,316 $5,570 $(21)$7,887 
 Nine months ended September 30, 2025
Balance at December 31, 2024$22 $2,316 $5,850 $(27)$8,161 
Net income574 574 
Other comprehensive income9 9 
Dividends declared:
Preferred stock ($1.13/share)
(1)(1)
Balance at September 30, 2025$22 $2,316 $6,423 $(18)$8,743 
Nine months ended September 30, 2024
Balance at December 31, 2023$22 $2,316 $5,095 $(23)$7,410 
Net income
476 476 
Other comprehensive income2 2 
Dividends declared:
Preferred stock ($1.13/share)
(1)(1)
Balance at September 30, 2024$22 $2,316 $5,570 $(21)$7,887 
See Notes to Condensed Financial Statements.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. GENERAL INFORMATION AND OTHER FINANCIAL DATA
PRINCIPLES OF CONSOLIDATION
Sempra
Sempra’s Condensed Consolidated Financial Statements include the accounts of Sempra, a California-based holding company, and its consolidated entities, which invest in, develop and operate energy infrastructure in North America, and provide electric and gas services to customers. Sempra has three operating and reportable segments, which we describe in Note 14. 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 Corporation, which is a wholly owned subsidiary of Sempra. SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County. SDG&E has one operating and reportable segment.
SoCalGas
SoCalGas’ common stock is wholly owned by Pacific Enterprises, which is a wholly owned subsidiary of Sempra. SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California. SoCalGas has one operating and reportable segment.
BASIS OF PRESENTATION
This is a combined report of Sempra, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. We have eliminated intercompany accounts and transactions within Sempra’s Condensed Consolidated Financial Statements.
We have prepared our Condensed Consolidated Financial Statements in conformity with U.S. GAAP and in accordance with the interim period reporting requirements of Form 10-Q and applicable rules of the SEC. The financial statements reflect all adjustments that are necessary for a fair presentation of the results for the interim periods. These adjustments are only of a normal, recurring nature. Results of operations for interim periods are not necessarily indicative of results for the entire year or for any other period. We evaluated events and transactions that occurred after September 30, 2025 through the date the financial statements were issued and, in the opinion of management, the accompanying financial statements reflect all adjustments and disclosures necessary for a fair presentation.
All December 31, 2024 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2024 Consolidated Financial Statements in the Annual Report. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the interim period reporting provisions of U.S. GAAP and the SEC.
We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report and the impact of the adoption of new accounting standards on those policies in Note 2 below. We follow the same accounting policies for interim period reporting purposes.
The information contained in this report should be read in conjunction with the Annual Report.
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. We discuss revenue recognition and the effects of regulation at our utilities in Notes 3 and 4 below and in Notes 1, 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.
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Our Sempra Texas Utilities segment is comprised of our equity method investments in holding companies that own interests in regulated electric transmission and distribution utilities in Texas.
Sempra Infrastructure’s natural gas distribution utility, Ecogas, also applies U.S. GAAP provisions governing rate-regulated operations, including the same evaluation of probability of recovery of regulatory assets described above. Certain business activities at Sempra Infrastructure are regulated by the CNE and the FERC and meet the regulatory accounting requirements of U.S. GAAP.

VARIABLE INTEREST ENTITIES
We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based on qualitative and quantitative analyses, which assess:
▪the purpose and design of the VIE;
▪the nature of the VIE’s risks and the risks we absorb;
▪the power to direct activities that most significantly impact the economic performance of the VIE; and
▪the obligation to absorb losses or the right to receive benefits that could be significant to the VIE.
We will continue to evaluate our VIEs for any changes that may impact our determination of whether an entity is a VIE and if we are the primary beneficiary.
SDG&E
SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various PPAs that include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and indirectly Sempra, is the primary beneficiary.
SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based on our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which it considers the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If SDG&E determines that it is the primary beneficiary, SDG&E and Sempra consolidate the entity that owns the facility as a VIE.
In addition to tolling agreements, other variable interests involve various elements of fuel and power costs, and other components of cash flows expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities, including the operation and maintenance activities of the generating facility, that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects could be significant to the financial position and liquidity of SDG&E and Sempra.
SDG&E determined that none of its PPAs and tolling agreements resulted in SDG&E being the primary beneficiary of a VIE at September 30, 2025 and December 31, 2024. PPAs and tolling agreements that relate to SDG&E’s involvement with VIEs are primarily accounted for as finance leases. The carrying amounts of the assets and liabilities under these contracts are included in PP&E, net, and finance lease liabilities with balances of $1,116 million and $1,138 million at September 30, 2025 and December 31, 2024, 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 15 of the Notes to Consolidated Financial Statements in the Annual Report. As a result, SDG&E’s potential exposure to loss from its variable interest in these VIEs is not significant.
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Other Sempra
Oncor Holdings
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 5 of the Notes to Consolidated Financial Statements in the Annual Report 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 is $17,038 million and $15,400 million at September 30, 2025 and December 31, 2024, respectively.
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 is $1,198 million, of which $1,181 million is classified as held for sale (see Note 6), at September 30, 2025 and $1,149 million at December 31, 2024. 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 13.
CFIN
As we discuss in Note 13, 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 9). Sempra’s maximum exposure to loss under the terms of the Support Agreement is $979 million, which we discuss in Note 13.
Other VIEs
ECA LNG Phase 1, Port Arthur LNG I and Port Arthur LNG II are VIEs because their total equity at risk is not sufficient to finance their activities without additional subordinated financial support. We expect that these entities will require future capital contributions or other financial support to finance the construction of their respective liquefaction facilities. Sempra is the primary beneficiary of these VIEs because we have the power to direct the activities that most significantly impact their economic performance, including construction and future operation and maintenance of the facilities. As a result, we consolidate these VIEs.
Sempra consolidated $14,130 million and $8,177 million of assets at September 30, 2025 and December 31, 2024, respectively, consisting primarily of PP&E, net, and restricted cash attributable to these VIEs that could be used only to settle obligations of these VIEs and that are not available to settle obligations of Sempra, and $5,288 million and $2,664 million of liabilities at September 30, 2025 and December 31, 2024, respectively, consisting primarily of long-term debt and accounts payable attributable to these VIEs for which creditors do not have recourse to the general credit of Sempra. At September 30, 2025, these assets and liabilities are classified as held for sale (see Note 6).
Additionally, IEnova and TotalEnergies SE have provided guarantees for repayment of up to $1,226 million and $305 million, respectively, plus accrued and unpaid interest, of the loan facility supporting construction of the ECA LNG Phase 1 project (see Note 7). Both SI Partners and ConocoPhillips have provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion (see Note 11). SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. SI Partners has committed to fund up to $7.8 billion to PA2 JVCo to support its share of the budgeted PA LNG Phase 2 project construction costs, while Blackstone has committed to fund $7.0 billion (see Note 10). SI Partners has also provided a guarantee for repayment of the $300 million credit facility supporting construction of the PA LNG Phase 2 project (see Note 7).

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on Sempra’s Condensed Consolidated Balance Sheets to the sum of such amounts reported on Sempra’s Condensed Consolidated Statements of Cash Flows. We provide information about the nature of restricted cash in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
RECONCILIATION OF CASH, CASH EQUIVALENTS AND RESTRICTED CASH
(Dollars in millions)
 September 30,
2025		December 31,
2024
Sempra:
Cash and cash equivalents$5 $1,565 
Restricted cash, current2 21 
Restricted cash, noncurrent— 3 
Assets held for sale3,018 — 
Total cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of
Cash Flows
$3,025 $1,589 
Restricted cash of $2.9 billion that is classified as held for sale at September 30, 2025 includes the following:
▪certain funds at Port Arthur LNG I for which withdrawals and usage are dictated by its debt agreements
▪certain funds at Port Arthur LNG II for which withdrawals and usage are dictated by the PA2 JVCo LLCA
▪funds denominated in U.S. dollars and Mexican pesos to pay for rights-of-way and other costs pursuant to certain agreements related to pipeline projects

CREDIT LOSSES
Financial Assets Measured at Amortized Cost
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 sales-type leases and a note receivable.
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.
As we discuss below in “Note Receivable,” we have an interest-bearing promissory note due from KKR Pinnacle. 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.
SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to Accounts Receivable – Trade that are probable of recovery in regulatory accounts. We discuss regulatory accounts in Note 4.
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Changes in allowances for credit losses for trade receivables, other receivables and a note receivable are as follows:
CHANGES IN ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
20252024
Sempra:
Allowances for credit losses at January 1$519 $539 
Provisions for expected credit losses(1)
106 148 
Write-offs(1)
(147)(169)
Reclassification to assets held for sale(134)— 
Allowances for credit losses at September 30
$344 $518 
SDG&E:
Allowances for credit losses at January 1$114 $144 
Provisions for expected credit losses40 46 
Write-offs(61)(63)
Allowances for credit losses at September 30
$93 $127 
SoCalGas:
Allowances for credit losses at January 1$285 $331 
Provisions for expected credit losses42 70 
Write-offs(80)(107)
Allowances for credit losses at September 30
$247 $294 
(1)    Includes activities within the disposal group that is held for sale.
Allowances for credit losses related to trade receivables, other receivables and a note receivable are included in the Condensed Consolidated Balance Sheets as follows:
ALLOWANCES FOR CREDIT LOSSES
(Dollars in millions)
September 30,December 31,
20252024
Sempra:
Accounts receivable – trade, net$270 $447 
Accounts receivable – other, net53 53 
Other long-term assets(1)(2)
21 19 
Total allowances for credit losses$344 $519 
SDG&E:
Accounts receivable – trade, net$61 $81 
Accounts receivable – other, net27 25 
Other long-term assets(1)
5 8 
Total allowances for credit losses$93 $114 
SoCalGas:
Accounts receivable – trade, net$209 $251 
Accounts receivable – other, net26 28 
Other long-term assets(1)
12 6 
Total allowances for credit losses$247 $285 
(1)    In January 2024, the CPUC directed SDG&E and SoCalGas to offer long-term repayment plans to eligible residential customers with past-due balances.
(2)    At September 30, 2025 and December 31, 2024, includes $4 and $5, respectively, of expected credit losses on an interest-bearing promissory note due from KKR Pinnacle.
Off-Balance Sheet Credit Exposures
We are exposed to credit losses from off-balance sheet arrangements through Sempra’s guarantees, which we discuss in Note 13. On a quarterly basis, we evaluate credit losses and record liabilities for expected credit losses on our off-balance sheet arrangements based on external credit ratings, published default rate studies and the maturity date of the arrangements. On Sempra’s Condensed Consolidated Balance Sheets, expected credit losses of $5 million are included in Deferred Credits and Other at both September 30, 2025 and December 31, 2024, and $3 million are included in Liabilities Held for Sale at September 30, 2025.
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TRANSACTIONS WITH AFFILIATES
We summarize amounts due from and to unconsolidated affiliates at the Registrants in the following table.
AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
 September 30,
2025		December 31,
2024
Sempra:  
Tax sharing agreement with Oncor Holdings$— $8 
Various affiliates— 5 
Total due from unconsolidated affiliates – current(1)
$— $13 
Tax sharing arrangement with Oncor Holdings$(17)$— 
Total due to unconsolidated affiliates – current$(17)$— 
TAG Pipelines Norte, S. de R.L. de C.V.(2):
5.5% Note due January 14, 2026
$— $(8)
5.5% Note due July 14, 2026
— (12)
5.5% Note due January 19, 2027
— (15)
5.5% Note due July 21, 2027
— (19)
5.5% Note due January 19, 2028
— (48)
5.5% Note due July 18, 2028
— (41)
TAG Norte – 5.74% Note due December 17, 2029(2)
— (209)
Total due to unconsolidated affiliates – noncurrent(1)
$— $(352)
SDG&E:  
SoCalGas
$13 $— 
Total due from unconsolidated affiliates – current$13 $— 
Sempra $(57)$(42)
SoCalGas— (14)
Various affiliates(8)(3)
Total due to unconsolidated affiliates – current$(65)$(59)
Income taxes due from Sempra(3)
$46 $38 
SoCalGas:  
SDG&E$— $14 
Various affiliates2 2 
Total due from unconsolidated affiliates – current$2 $16 
Sempra$(49)$(38)
SDG&E(13)— 
Total due to unconsolidated affiliates – current$(62)$(38)
Income taxes due from (to) Sempra(3)
$20 $(6)
(1)     At September 30, 2025, $3 due from unconsolidated affiliates is classified as Assets Held For Sale and $417 due to unconsolidated affiliates is classified as Liabilities Held For Sale on the Sempra Condensed Consolidated Balance Sheet.
(2)     U.S. dollar-denominated loans at fixed interest rates. Amounts include principal balances plus accumulated interest outstanding and value added tax payable to the Mexican government.
(3)    SDG&E and SoCalGas are included in the consolidated income tax return of Sempra, and their respective income tax expense/benefit 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 from/to Sempra.
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The following table summarizes income statement information from unconsolidated affiliates.
INCOME STATEMENT IMPACT FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra:    
Revenues$9 $11 $26 $31 
Interest expense4 5 13 12 
SDG&E:    
Revenues$6 $6 $17 $17 
Cost of sales35 36 103 111 
SoCalGas:
Revenues$47 $43 $128 $124 
Cost of sales(1)
(2)(2)(3)(5)
(1)     Includes net commodity costs from natural gas transactions with unconsolidated affiliates.
Guarantees
Sempra provides guarantees to certain unconsolidated affiliates, which we discuss in Note 13.

INVENTORIES
The components of inventories are as follows:
INVENTORY BALANCES
(Dollars in millions)
 SempraSDG&ESoCalGas
 
September 30,
2025(1)
December 31,
2024		September 30,
2025		December 31,
2024		September 30,
2025		December 31,
2024
Natural gas$162 $163 $2 $1 $160 $148 
LNG— 27 — — — — 
Materials and supplies403 369 261 201 142 139 
Total$565 $559 $263 $202 $302 $287 
(1)    Total inventories of $103 is classified as Assets Held For Sale on the Sempra Condensed Consolidated Balance Sheet, which consists of $10 of natural gas, $11 of LNG and $82 of materials and supplies.

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 $585 million at both September 30, 2025 and December 31, 2024.

WILDFIRE FUND AND CONTINUATION ACCOUNT
2019 Wildfire Legislation
In July 2019, the 2019 Wildfire Legislation was signed into law to address certain issues related to catastrophic wildfires in California and their impact on electric IOUs through the establishment of the Wildfire Fund. We discuss the 2019 Wildfire Legislation and related Wildfire Fund further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E expects to submit its request to the OEIS for its annual wildfire safety certification in December 2025. OEIS will have until March 2026 to issue the certification or provide written notice explaining why additional time is needed. SDG&E’s existing certification remains valid until this pending request is resolved.
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Wildfire Fund Asset
At September 30, 2025, the carrying value of SDG&E’s Wildfire Fund asset totaled $264 million.
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. SDG&E periodically evaluates the estimated period of benefit of the Wildfire Fund asset based on actual experience and changes in assumptions, including relying on publicly disclosed wildfire-related losses incurred by the other participating IOUs.
In October 2025, a participating IOU publicly disclosed that it has received, or expects to receive, approximately $1.2 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021. In the three months and nine months ended September 30, 2025, SDG&E reduced its Wildfire Fund asset by recording $2 million of accelerated amortization in O&M on Sempra’s and SDG&E’s Condensed Consolidated Statements of Operations.
Also in October 2025, another participating IOU publicly disclosed its intent to seek reimbursement from the Wildfire Fund for losses incurred and expected to be incurred in connection with a wildfire that remains under investigation, and for which the cause has not yet been conclusively determined. The administrator of the Wildfire Fund has confirmed that this wildfire qualifies as a “covered wildfire” for purposes of accessing the fund. The participating IOU has stated that it is currently unable to reasonably estimate a range of potential losses associated with this event. Accordingly, SDG&E is unable to estimate a range of potential loss resulting from any reduction in available coverage from the Wildfire Fund.
2025 Wildfire Legislation
In September 2025, the 2025 Wildfire Legislation was signed into law. The 2025 Wildfire Legislation established, among other things, the Continuation Account, a new state-administered account with up to $18.0 billion of additional liquidity to reimburse catastrophic wildfire-related claims incurred by large California electric IOUs, including SDG&E, if the Wildfire Fund is depleted. The 2025 Wildfire Legislation preserves key elements of the 2019 Wildfire Legislation, including cost recovery standards and requirements, a cap on liability in the event of a finding of imprudence by the CPUC, and continued access to wildfire claims liquidity through the new Continuation Account.
The Continuation Account will become operative if, prior to December 31, 2028, either (i) the Wildfire Fund’s administrator projects that the original Wildfire Fund will be depleted, or (ii) a participating electric IOU notifies the Wildfire Fund’s administrator that it anticipates more than $1.0 billion in eligible claims in a single coverage year for one or more wildfires that ignite after September 19, 2025, the effective date of the 2025 Wildfire Legislation. All of California’s large electric IOUs, including SDG&E, have elected to participate in the Continuation Account.
If the Continuation Account becomes operative, it would be funded with a combination of ratepayer and electric IOU shareholder contributions. Ratepayer contributions totaling $9.0 billion would be financed through new bonds to be issued by the California Department of Water Resources and secured by the extension of an existing Wildfire Fund-related non-bypassable ratepayer charge from 2036-2045, subject to a determination by the CPUC that the extension is just and reasonable. Electric IOU shareholder contributions totaling $5.1 billion would be obtained through fixed annual contributions of $300 million from 2029 through 2045, plus an additional $3.9 billion in contingent shareholder contributions payable in annual installments of $780 million if the Wildfire Fund’s administrator determines there is additional need, subject to a potential ratepayer credit of 50% of the amount of any remaining contingent contribution installments if the Wildfire Fund’s administrator terminates the Continuation Account prior to their collection. SDG&E’s proportionate share of the aggregate shareholder contribution amount through 2045 is expected to be $387 million, comprising (i) $219.3 million of fixed contributions of $12.9 million annually for 17 years, and (ii) $167.7 million of contingent contributions of $33.5 million annually for five years.
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Only claims arising from wildfires that ignited on or after September 19, 2025 in excess of the greater of $1.0 billion or the amount of insurance coverage required by the Wildfire Fund’s administrator are eligible for reimbursement from the Continuation Account. As with the 2019 Wildfire Legislation, for participating electric IOUs that have received a safety certification, reimbursements to the Continuation Account with electric IOU shareholder contributions are not required if a CPUC reasonableness review, conducted under the prudency standards established by the 2019 Wildfire Legislation, results in a finding that the participating IOU acted prudently. Reimbursements to the Continuation Account with electric IOU shareholder contributions are required for wildfire liabilities deemed imprudently incurred, but the amount of the reimbursement is subject to a cap if the Continuation Account is not otherwise depleted. The applicable participating electric IOU may credit its shareholder contributions to the Continuation Account against required reimbursements, subject to a cap equal to the lesser of (i) the disallowed costs, or (ii) 20% of the electric IOU’s total transmission and distribution equity rate base for the year of ignition of the applicable wildfire, less (a) prior reimbursements by the electric IOU for any covered wildfire-related disallowances within three years before the date of ignition of the applicable wildfire, and (b) any unused shareholder contributions by the electric IOU not already credited. SDG&E’s current estimated cap, which will vary over time, is approximately $1.4 billion based on its 2024 transmission and distribution equity rate base.
As with the 2019 Wildfire Legislation, participating electric IOUs are not permitted to earn an equity return on a certain amount of capital investments supporting wildfire risk mitigation. The 2025 Wildfire Legislation establishes this amount as $6.0 billion of wildfire risk mitigation capital investments authorized by the CPUC after January 1, 2026, and SDG&E’s proportionate share is limited to $258 million.
If the Continuation Account becomes operative, SDG&E would record an obligation for its commitment to make shareholder contributions to the Continuation Account.

NOTE RECEIVABLE
In November 2021, Sempra loaned $300 million to KKR Pinnacle in exchange for an interest-bearing promissory note that is due in full no later than October 2029 and bears compound interest at 5% per annum, which may be paid quarterly or added to the outstanding principal at the election of KKR Pinnacle. At September 30, 2025 and December 31, 2024, Other Long-Term Assets includes $363 million and $349 million, respectively, of outstanding principal, compounded interest and unamortized transaction costs, net of allowance for credit losses, on Sempra’s Condensed Consolidated Balance Sheets.
At the closing of the sale of a portion of our equity interest in SI Partners, which we discuss in Note 6, Sempra and the KKR Partners will amend this $300 million promissory note to, among other things, extend its maturity date and increase its interest rate to 8.5% per annum before January 1, 2031 and 10.0% thereafter through a due date seven years and 91 days after the closing.

PROPERTY, PLANT AND EQUIPMENT
Sempra Infrastructure’s Sonora natural gas pipeline consists of two pipeline segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017 because it was not able to be repaired due to legal challenges, which were resolved in March 2023, by some members of the Yaqui tribe. Sempra Infrastructure and the CFE have agreed to an amendment to their transportation services agreement and to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE would pay for the re-routing with a new tariff. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Sempra Infrastructure continues to acquire and pursue the necessary rights-of-way and permits for the portion of the pipeline that needs to be re-routed.
The Guaymas-El Oro segment will continue to be owned by and a Sole Risk Project of Sempra after closing the sale of a portion of our equity interest in SI Partners, which we discuss in Note 6. At September 30, 2025, Sempra Infrastructure has $391 million in PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if, among other things, Sempra Infrastructure is unable to re-route a portion of the pipeline and resume operations or if Sempra Infrastructure terminates the contract and is unable to obtain recovery.

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CAPITALIZED FINANCING COSTS
The table below summarizes capitalized financing costs, comprised of capitalized interest and AFUDC related to debt.
CAPITALIZED FINANCING COSTS
(Dollars in millions)
Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra$205 $166 $574 $466 
SDG&E25 27 82 80 
SoCalGas25 25 75 75 

ASSET RETIREMENT OBLIGATIONS
We discuss AROs in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We summarize changes in AROs in the following table.
CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
SempraSDG&ESoCalGas
202520242025202420252024
Balance at January 1(1)
$3,925 $3,831 $900 $894 $2,930 $2,847 
Accretion expense(2)
121 115 30 27 88 84 
Liabilities incurred
9 — 9 — — — 
Payments
(48)(45)(39)(40)(9)(5)
Revisions(2)
50 (9)(6)— 59 (9)
Reclassification to liabilities held for sale
(93)— — — — — 
Balance at September 30(1)
$3,964 $3,892 $894 $881 $3,068 $2,917 
(1)    Current portion of the ARO for Sempra is included in Other Current Liabilities on the Condensed Consolidated Balance Sheets.
(2)    Sempra includes activities within the disposal group that is held for sale.

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COMPREHENSIVE INCOME
The following tables present the changes in AOCI by component and amounts reclassified out of AOCI to net income, after amounts attributable to NCI.
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
(Dollars in millions)
 Foreign
currency
translation
adjustments		Financial
instruments		Pension
and PBOP		Total
AOCI
 Three months ended September 30, 2025 and 2024
Sempra:
Balance at June 30, 2025$(55)$(50)$(110)$(215)
OCI before reclassifications5 (11)(1)(7)
Amounts reclassified from AOCI
— (2)12 10 
Net OCI
5 (13)11 3 
Balance at September 30, 2025$(50)$(63)$(99)$(212)
   
Balance at June 30, 2024$(49)$35 $(107)$(121)
OCI before reclassifications
(12)(49)— (61)
Amounts reclassified from AOCI
— (5)2 (3)
Net OCI
(12)(54)2 (64)
Balance at September 30, 2024$(61)$(19)$(105)$(185)
SDG&E:
Balance at June 30, 2025 and September 30, 2025$(12)$(12)
Balance at June 30, 2024 and September 30, 2024$(8)$(8)
SoCalGas:
Balance at June 30, 2025$(10)$(14)$(24)
Amounts reclassified from AOCI1 5 6 
Net OCI1 5 6 
Balance at September 30, 2025$(9)$(9)$(18)
Balance at June 30, 2024 and September 30, 2024$(10)$(11)$(21)
(1)    All amounts are net of income tax, if subject to tax, and after NCI.

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CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1) (CONTINUED)
(Dollars in millions)
 Foreign
currency
translation
adjustments		Financial
instruments		Pension
and PBOP		Total
AOCI
 Nine months ended September 30, 2025 and 2024
Sempra:
Balance at December 31, 2024$(66)$15 $(115)$(166)
OCI before reclassifications16 (76)(3)(63)
Amounts reclassified from AOCI
— (2)19 17 
Net OCI
16 (78)16 (46)
Balance at September 30, 2025$(50)$(63)$(99)$(212)
   
Balance at December 31, 2023$(36)$3 $(117)$(150)
OCI before reclassifications
(25)(1)1 (25)
Amounts reclassified from AOCI
— (21)11 (10)
Net OCI
(25)(22)12 (35)
Balance at September 30, 2024$(61)$(19)$(105)$(185)
SDG&E:
Balance at December 31, 2024 and September 30, 2025$(12)$(12)
Balance at December 31, 2023 and September 30, 2024$(8)$(8)
SoCalGas:
Balance at December 31, 2024$(10)$(17)$(27)
OCI before reclassifications— (2)(2)
Amounts reclassified from AOCI1 10 11 
Net OCI1 8 9 
Balance at September 30, 2025$(9)$(9)$(18)
Balance at December 31, 2023$(11)$(12)$(23)
Amounts reclassified from AOCI
1 1 2 
Net OCI1 1 2 
Balance at September 30, 2024$(10)$(11)$(21)
(1)    All amounts are net of income tax, if subject to tax, and after NCI.
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RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about AOCI componentsAmounts reclassified
from AOCI		 Affected line item on Condensed
Consolidated Statements of Operations
 Three months ended September 30,  
 20252024 
Sempra:   
Financial instruments:   
Interest rate instruments
$(4)$(3)Interest expense
Interest rate instruments
(6)(5)
Equity earnings(1)
Foreign exchange instruments2 — 
Revenues: Energy-related businesses
Foreign exchange instruments1 (1)Other income, net
Foreign exchange instruments3 (1)
Equity earnings(1)
Total, before income tax
(4)(10) 
 1 3 Income tax (expense) benefit
Total, net of income tax
(3)(7) 
 1 2 Earnings attributable to noncontrolling interests
Total, net of income tax and after NCI$(2)$(5) 
Pension and PBOP(2):
   
Amortization of actuarial loss$2 $2 Other income, net
Amortization of prior service cost— 1 Other income, net
Settlement charges12 — Other income, net
Total, before income tax
14 3 
 (2)(1)Income tax (expense) benefit
Total, net of income tax
$12 $2  
Total reclassifications for the period, net of income
 tax and after NCI
$10 $(3) 
SoCalGas:   
Financial instruments:
Interest rate instruments$1 $— Interest expense
Pension and PBOP(2):
   
Settlement charges
$6 $— Other (expense) income, net
Total, before income tax6 — 
(1)— Income tax benefit (expense)
Total, net of income tax$5 $— 
Total reclassifications for the period, net of income
 tax
$6 $— 
(1)    Equity earnings at Oncor Holdings and our foreign equity method investees are recognized after tax.
(2)    Amounts are included in the computation of net periodic benefit cost (see “Pension and PBOP” below).
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RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (CONTINUED)
(Dollars in millions)
Details about AOCI componentsAmounts reclassified
from AOCI		Affected line item on Condensed
Consolidated Statements of Operations
Nine months ended September 30,
20252024
Sempra:
Financial instruments:
Interest rate instruments$(6)$(9)Interest expense
Interest rate instruments(10)(20)
Equity earnings(1)
Foreign exchange instruments3 (5)
Revenues: Energy-related businesses
2 (2)Other income, net
Foreign exchange instruments4 (5)
Equity earnings(1)
Total, before income tax
(7)(41)
2 9 Income tax (expense) benefit
Total, net of income tax
(5)(32)
3 11 Earnings attributable to noncontrolling interests
Total, net of income tax and after NCI$(2)$(21)
Pension and PBOP(2):
  
Amortization of actuarial loss$5 $5 Other income, net
Amortization of prior service cost1 2 Other income, net
Settlement charges16 9 Other income, net
Total, before income tax
22 16 
(3)(5)Income tax (expense) benefit
Total, net of income tax
$19 $11 
Total reclassifications for the period, net of income
 tax and after NCI
$17 $(10)
SoCalGas:   
Financial instruments:
Interest rate instruments$1 $1 Interest expense
Pension and PBOP(2):
   
Amortization of actuarial loss$1 $— Other (expense) income, net
Amortization of prior service cost1 1 Other (expense) income, net
Settlement charges
10 — Other (expense) income, net
Total, before income tax12 1 
(2)— Income tax benefit (expense)
Total, net of income tax$10 $1 
Total reclassifications for the period, net of income
 tax
$11 $2 
(1)    Equity earnings at Oncor Holdings and our foreign equity method investees are recognized after tax.
(2)    Amounts are included in the computation of net periodic benefit cost (see “Pension and PBOP” below).

In the three months and nine months ended September 30, 2025 and 2024, reclassifications out of AOCI to net income were negligible for SDG&E.

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PENSION AND PBOP
Special Termination Benefits
In the second quarter of 2025, certain eligible employees retired under a VREP and received an additional postretirement health benefit in the form of a $100,000 Health Reimbursement Account. Employees eligible to participate in the VREP consisted of SDG&E represented and non-represented employees and SoCalGas non-represented employees aged 62 years or older with five years of service or ages 55 to 61 with 10 years of service as of May 31, 2025, and SoCalGas represented employees aged 65 or older with five years of service or ages 55 to 64 with 15 years of service as of June 30, 2025. We treated the benefit obligation attributable to the Health Reimbursement Account as a special termination benefit. This resulted in increases to the recorded liability for PBOP and net periodic benefit cost of $40 million for Sempra, $17 million for SDG&E and $23 million for SoCalGas in the nine months ended September 30, 2025.
Partial Plan Termination
In connection with the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6, Sempra entered into an agreement to contribute Sempra Services Corporation, a wholly owned subsidiary of Sempra, to SI Partners. Sempra Services Corporation employs U.S. employees performing services for SI Partners and is a participating employer in Sempra’s noncontributory defined benefit pension and PBOP plans. Upon closing the sale, which we expect to occur in the second or third quarter of 2026, Sempra Services Corporation will cease to be a participating employer in Sempra’s pension and PBOP plans. This will result in a partial termination of Sempra’s pension plan due to a reduction in the number of active participants by more than 20%. All impacted participants will be fully vested in their pension benefits as of the termination date. We expect to recognize the financial statement impact, which is currently probable but not estimable, including adjustments to pension and PBOP liabilities, AOCI, curtailment and special termination benefit accounting at the close of the sale. The financial impact for settlement accounting will be recognized when the lump sum payout crosses the annual settlement threshold.

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Net Periodic Benefit Cost
The following tables provide the components of net periodic benefit cost. The components of net periodic benefit cost, other than the service cost component, are included in Other Income, Net.
NET PERIODIC BENEFIT COST
(Dollars in millions)
PensionPBOP
 Three months ended September 30,
 2025202420252024
Sempra:
Service cost$32 $34 $3 $4 
Interest cost42 41 10 9 
Expected return on assets(41)(40)(17)(19)
Amortization of:    
Prior service cost (credit)1 1 (1)(1)
Actuarial loss (gain)3 4 (3)(4)
Settlement charges12 — — — 
Net periodic benefit cost (credit)49 40 (8)(11)
Regulatory adjustments26 20 8 10 
Total expense (income) recognized$75 $60 $— $(1)
SDG&E:
Service cost$10 $10 $— $— 
Interest cost11 10 2 3 
Expected return on assets(11)(10)(2)(3)
Amortization of:
Actuarial loss 1 3 — — 
Net periodic benefit cost 11 13 — — 
Regulatory adjustments2 — — — 
Total expense recognized$13 $13 $— $— 
SoCalGas:
Service cost$19 $21 $2 $3 
Interest cost28 26 7 7 
Expected return on assets(30)(29)(13)(15)
Amortization of:
Prior service cost (credit)1 1 (1)(1)
Actuarial gain (loss)1 1 (3)(4)
Settlement charges6 — — — 
Net periodic benefit cost (credit)25 20 (8)(10)
Regulatory adjustments24 20 8 10 
Total expense recognized$49 $40 $— $— 


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NET PERIODIC BENEFIT COST (CONTINUED)
(Dollars in millions)
PensionPBOP
 Nine months ended September 30,
 2025202420252024
Sempra:
Service cost$96 $99 $10 $11 
Interest cost132 124 29 27 
Expected return on assets(130)(131)(50)(53)
Amortization of:    
Prior service cost (credit)3 4 (2)(2)
Actuarial loss (gain)9 10 (9)(12)
Settlement charges16 9 — — 
Special termination benefits— — 40 — 
Net periodic benefit cost (credit)126 115 18 (29)
Regulatory adjustments25 21 (15)28 
Total expense (income) recognized$151 $136 $3 $(1)
SDG&E:
Service cost$29 $29 $1 $2 
Interest cost35 32 6 6 
Expected return on assets(35)(33)(6)(7)
Amortization of:
Actuarial loss (gain)3 6 (1)(1)
Special termination benefits— — 17 — 
Net periodic benefit cost 32 34 17 — 
Regulatory adjustments(6)(7)(14)— 
Total expense recognized$26 $27 $3 $— 
SoCalGas:
Service cost$57 $59 $7 $8 
Interest cost84 78 22 21 
Expected return on assets(89)(90)(42)(45)
Amortization of:
Prior service cost (credit)3 3 (2)(2)
Actuarial loss (gain)2 1 (7)(10)
Settlement charges10 — — — 
Special termination benefits— — 23 — 
Net periodic benefit cost (credit)67 51 1 (28)
Regulatory adjustments31 28 (1)28 
Total expense recognized$98 $79 $— $— 
Benefit Plan Contributions
The following table shows our year-to-date contributions to pension and PBOP plans and the amounts we expect to contribute in 2025.
BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
SempraSDG&ESoCalGas
Contributions through September 30, 2025:
Pension plans$158 $26 $110 
PBOP plans2— 1
Total expected contributions in 2025:
Pension plans$292 $56 $196 
PBOP plans16131 
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OTHER INCOME, NET
Other Income, Net, consists of the following:
OTHER INCOME (EXPENSE), NET
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra: 
Allowance for equity funds used during construction$43 $39 $130 $114 
Investment gains, net(1)
22 29 47 48 
(Losses) gains on interest rate and foreign exchange instruments, net
(1)1 (2)2 
Foreign currency transaction gains (losses), net
4 (5)10 (6)
Non-service components of net periodic benefit cost
(40)(21)(48)(25)
Interest on regulatory balancing accounts, net29 26 70 68 
Sundry, net(8)(4)(8)(7)
Total$49 $65 $199 $194 
SDG&E: 
Allowance for equity funds used during construction$19 $21 $61 $60 
Non-service components of net periodic benefit cost
(3)(3)1 4 
Interest on regulatory balancing accounts, net18 12 44 30 
Sundry, net(2)— (3)(8)
Total$32 $30 $103 $86 
SoCalGas: 
Allowance for equity funds used during construction$17 $18 $53 $54 
Non-service components of net periodic benefit cost
(28)(16)(34)(12)
Interest on regulatory balancing accounts, net11 14 26 38 
Sundry, net(3)(3)(8)(7)
Total$(3)$13 $37 $73 
(1)    Represents net investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are offset by corresponding changes in compensation expense related to the plans, recorded in O&M on the Condensed Consolidated Statements of Operations.

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INCOME TAXES
We provide our calculations of ETRs in the following table.
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Three months ended September 30,Nine months ended September 30,
2025202420252024
Sempra:
Income tax expense (benefit)$482 $(105)$711 $(63)
Income before income taxes and equity earnings
$160 $200 $1,109 $1,213 
Equity earnings, before income tax(1)
133 132 443 426 
Pretax income
$293 $332 $1,552 $1,639 
Effective income tax rate165 %(32)%46 %(4)%
SDG&E:
Income tax (benefit) expense$(33)$15 $(12)$89 
Income before income taxes$291 $276 $768 $759 
Effective income tax rate(11)%5 %(2)%12 %
SoCalGas:
Income tax (benefit) expense$(95)$(52)$(51)$1 
(Loss) income before income taxes
$(49)$(66)$523 $477 
Effective income tax rate194 %79 %(10)%— %
(1)    We discuss how we recognize equity earnings in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
Sempra, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted ETR anticipated for the full year. Unusual and infrequent items and items that cannot be reliably estimated are recorded in the interim period in which they occur, which can result in variability in the ETR.
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 that will be flowed through to customers in the future, 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. Items subject to flow-through treatment include:
▪repairs expenditures related to certain utility plant fixed assets
▪the equity component of AFUDC, which is non-taxable
▪cost of removal related to certain utility plant assets
▪utility self-developed software expenditures
▪depreciation related to certain utility plant assets
▪state income taxes
AFUDC related to equity recorded for regulated construction projects at Sempra Infrastructure has similar flow-through treatment.
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The OBBBA was signed into law on July 4, 2025. The OBBBA includes revisions to tax credits and other incentives for energy and climate initiatives of the Inflation Reduction Act enacted in 2022 and extends or revises key provisions of the TCJA, among other changes. Effective January 1, 2025, we have adopted the provisions of OBBBA, which include immediate expensing of domestic research and experimental expenditures, including utility self-developed software expenditures, under the new Internal Revenue Code Section 174A. This change supersedes prior rules requiring five-year amortization of domestic research and experimental expenditures under the TCJA. In accordance with IRS transitional guidance (Revenue Procedure 2025-28), we plan to elect to accelerate deductions for domestic unamortized utility self-developed software expenditures incurred in tax years 2022-2024, with remaining balances deductible over 2025 and 2026. As a result, Sempra, SDG&E and SoCalGas recorded an income tax benefit of $73 million, $26 million and $47 million, respectively, in the three months and nine months ended September 30, 2025. We will continue to monitor guidance issued by the U.S. Department of the Treasury and the IRS.
In connection with classifying SI Partners and Ecogas as held for sale, which we discuss in Note 6, we recognized income tax expense of $514 million and $552 million in the three months and nine months ended September 30, 2025, respectively. We have previously included unrecognized income tax benefits in our annual tabular reconciliation related to our investment in SI Partners. As a result of the held for sale classification and the anticipated closing of the sale, we believe it is reasonably possible that a decrease of up to $150 million in unrecognized income tax benefits related to outside basis differences and Mexico tax liabilities will be necessary in the next 12 months. These changes in unrecognized income tax benefits would not decrease or increase the effective tax rate.
NOTE 2. NEW ACCOUNTING STANDARDS
We describe below recent accounting pronouncements that have had or may have a significant effect on our results of operations, financial condition, cash flows or disclosures.
ASU 2023-09, “Improvements to Income Tax Disclosures”: ASU 2023-09 improves the transparency of income tax disclosures by requiring disaggregated information about each Registrant’s ETR reconciliation as well as information on income taxes paid. For each annual period, each Registrant will be required to disclose specific categories in the rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold (if the effect of those reconciling items is equal to or greater than 5% of the amount computed by multiplying pretax income or loss by the applicable statutory income tax rate). ASU 2023-09 is effective for annual periods beginning after December 15, 2024. We will adopt the standard on December 31, 2025.
ASU 2024-03, “Disaggregation of Income Statement Expenses”: ASU 2024-03 mandates detailed disclosures on the disaggregation of income statement expenses. Public business entities are required to disclose in the notes to financial statements the amounts of purchases of inventory, employee compensation, depreciation and intangible asset amortization included in each relevant expense caption. The standard also requires disclosure of the amount, and a qualitative description of, other items remaining in relevant expense captions that are not separately disaggregated. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted, and entities may adopt the standard on either a prospective or retrospective basis. We intend to adopt the standard on January 1, 2027 on a prospective basis.
ASU 2025-05, “Measurement of Credit Losses for Accounts Receivable and Contract Assets”: ASU 2025-05 amends ASC 326-20 to provide a practical expedient for all entities related to the estimation of expected credit losses for current accounts receivable and current contract assets that arise from transactions accounted for under ASC 606, Revenue from Contracts with Customers. ASU 2025-05 is effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods on a prospective basis. We intend to adopt the standard on January 1, 2026 and expect to elect the practical expedient on a prospective basis for eligible current accounts receivable and contract assets. We do not expect this ASU to have a material impact on our financial statements.
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NOTE 3. REVENUES
We discuss revenue recognition for revenues from contracts with customers and from sources other than contracts with customers in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.
The following tables disaggregate our revenues from contracts with customers by major service line and market. We also provide a reconciliation to total revenues by segment for Sempra. The majority of our revenue is recognized over time.
DISAGGREGATED REVENUES
(Dollars in millions)
Sempra
Sempra CaliforniaSempra InfrastructureConsolidating adjustments and Parent
and other		Sempra
Three months ended September 30, 2025
By major service line:
Utilities$2,518 $15 $(5)$2,528 
Energy-related businesses— 241 (13)228 
Revenues from contracts with customers$2,518 $256 $(18)$2,756 
By market:
Gas$1,390 $156 $(3)$1,543 
Electric1,128 100 (15)1,213 
Revenues from contracts with customers$2,518 $256 $(18)$2,756 
Revenues from contracts with customers$2,518 $256 $(18)$2,756 
Utilities regulatory revenues95 — — 95 
Other revenues— 299 1 300 
Total revenues$2,613 $555 $(17)$3,151 
Three months ended September 30, 2024
By major service line:
Utilities$2,394 $15 $(7)$2,402 
Energy-related businesses— 179 (12)167 
Revenues from contracts with customers$2,394 $194 $(19)$2,569 
By market:
Gas$1,237 $83 $(6)$1,314 
Electric1,157 111 (13)1,255 
Revenues from contracts with customers$2,394 $194 $(19)$2,569 
Revenues from contracts with customers$2,394 $194 $(19)$2,569 
Utilities regulatory revenues(138)— — (138)
Other revenues— 344 1 345 
Total revenues$2,256 $538 $(18)$2,776 
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DISAGGREGATED REVENUES (CONTINUED)
(Dollars in millions)
Sempra
Sempra CaliforniaSempra InfrastructureConsolidating adjustments and Parent
and other		Sempra
Nine months ended September 30, 2025
By major service line:
Utilities$8,430 $59 $(18)$8,471 
Energy-related businesses— 716 (50)666 
Revenues from contracts with customers$8,430 $775 $(68)$9,137 
By market:
Gas$5,378 $471 $(16)$5,833 
Electric3,052 304 (52)3,304 
Revenues from contracts with customers$8,430 $775 $(68)$9,137 
Revenues from contracts with customers$8,430 $775 $(68)$9,137 
Utilities regulatory revenues74 — — 74 
Other revenues— 736 6 742 
Total revenues$8,504 $1,511 $(62)$9,953 
 Nine months ended September 30, 2024
By major service line:
Utilities$8,129 $63 $(18)$8,174 
Energy-related businesses— 625 (49)576 
Revenues from contracts with customers$8,129 $688 $(67)$8,750 
By market:
Gas$4,961 $356 $(15)$5,302 
Electric3,168 332 (52)3,448 
Revenues from contracts with customers$8,129 $688 $(67)$8,750 
Revenues from contracts with customers$8,129 $688 $(67)$8,750 
Utilities regulatory revenues(107)— — (107)
Other revenues— 778 6 784 
Total revenues$8,022 $1,466 $(61)$9,427 

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DISAGGREGATED REVENUES
(Dollars in millions)
SDG&ESoCalGas
Three months ended September 30,
2025202420252024
By major service line:
Revenues from contracts with customers – Utilities
$1,349 $1,327 $1,217 $1,110 
By market:
Gas$218 $167 $1,217 $1,110 
Electric1,131 1,160 — — 
Revenues from contracts with customers$1,349 $1,327 $1,217 $1,110 
Revenues from contracts with customers$1,349 $1,327 $1,217 $1,110 
Utilities regulatory revenues131 (84)(36)(56)
Total revenues$1,480 $1,243 $1,181 $1,054 
Nine months ended September 30,
2025202420252024
By major service line:
Revenues from contracts with customers – Utilities
$3,851 $3,836 $4,706 $4,416 
By market:
Gas$789 $658 $4,706 $4,416 
Electric3,062 3,178 — — 
Revenues from contracts with customers$3,851 $3,836 $4,706 $4,416 
Revenues from contracts with customers$3,851 $3,836 $4,706 $4,416 
Utilities regulatory revenues311 141 (237)(248)
Total revenues$4,162 $3,977 $4,469 $4,168 
REVENUES FROM CONTRACTS WITH CUSTOMERS
Remaining Performance Obligations
For contracts greater than one year, at September 30, 2025, 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 for contracts greater than one year at September 30, 2025.
REMAINING PERFORMANCE OBLIGATIONS
(Dollars in millions)
Sempra(1)
SDG&E
2025 (excluding first nine months of 2025)$104 $1 
2026292 4 
2027291 4 
2028245 4 
2029217 4 
Thereafter2,143 52 
Total revenues to be recognized
$3,292 $69 
(1)    Excludes intercompany transactions. Includes obligations within the disposal group that is held for sale.
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Contract Liabilities from Revenues from Contracts with Customers
Activities within Sempra’s and SDG&E’s contract liabilities are presented below. There were no contract liabilities at SoCalGas in the nine months ended September 30, 2025 or 2024.
CONTRACT LIABILITIES
(Dollars in millions)
20252024
Sempra:
Contract liabilities at January 1$(196)$(198)
Revenue from performance obligations satisfied during reporting period(1)
83 5 
Payments received in advance(1)
(1)(3)
Reclassification to liabilities held for sale45 — 
Contract liabilities at September 30(2)
$(69)$(196)
SDG&E:
Contract liabilities at January 1$(72)$(75)
Revenue from performance obligations satisfied during reporting period3 3 
Contract liabilities at September 30(2)
$(69)$(72)
(1)    Includes activities within the disposal group that is held for sale.
(2)    Balance at September 30, 2025 includes $4 in Other Current Liabilities and $65 in Deferred Credits and Other.
Receivables from Revenues from Contracts with Customers
The table below shows receivable balances, net of allowances for credit losses, associated with revenues from contracts with customers on the Condensed Consolidated Balance Sheets.
RECEIVABLES FROM REVENUES FROM CONTRACTS WITH CUSTOMERS
(Dollars in millions)
September 30, 2025December 31, 2024
Sempra:
Accounts receivable – trade, net(1)
$1,409 $1,787 
Accounts receivable – other, net12 12 
Due from unconsolidated affiliates – current(2)
— 4 
Assets held for sale125 — 
Other long-term assets(3)
19 18 
Total$1,565 $1,821 
SDG&E:
Accounts receivable – trade, net(1)
$849 $774 
Accounts receivable – other, net10 11 
Due from unconsolidated affiliates – current(2)
12 6 
Other long-term assets(3)
3 4 
Total$874 $795 
SoCalGas:
Accounts receivable – trade, net$560 $932 
Accounts receivable – other, net2 1 
Other long-term assets(3)
16 14 
Total$578 $947 
(1)     At September 30, 2025 and December 31, 2024, includes $218 and $144, 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 Condensed Consolidated Balance Sheets, when right of offset exists.
(3)     In January 2024, the CPUC directed SDG&E and SoCalGas to offer long-term repayment plans to eligible residential customers with past-due balances.

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NOTE 4. REGULATORY MATTERS
REGULATORY ASSETS AND LIABILITIES
We discuss regulatory matters in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report and provide updates to those discussions and information about new regulatory matters below. With the exception of regulatory balancing accounts, we generally do not earn a return on our regulatory assets until 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.
REGULATORY ASSETS (LIABILITIES)
(Dollars in millions)
SempraSDG&ESoCalGas
September 30,
2025
December 31,
2024		September 30,
2025		December 31,
2024		September 30,
2025		December 31,
2024
Fixed-price contracts and other
derivatives
$71 $53 $6 $11 $65 $42 
Deferred income taxes recoverable in rates(1)
2,181 1,689 1,071 802 1,086 817 
Pension and PBOP plan obligations
(462)(458)17 (2)(479)(456)
Employee benefit costs19 19 3 3 16 16 
Removal obligations(3,466)(3,295)(2,856)(2,676)(610)(619)
Environmental costs149 149 114 115 35 34 
Sunrise Powerlink fire mitigation124 124 124 124 — — 
Regulatory balancing accounts(2):
Commodity – electric108 (313)108 (313)— — 
Commodity – gas, including
transportation
32 (47)(2)86 34 (133)
Safety and reliability
885 820 296 227 589 593 
Public purpose programs(402)(439)(160)(219)(242)(220)
2024 GRC retroactive impacts420 631 177 277 243 354 
Wildfire mitigation plan
982 808 982 808 — — 
Liability insurance premium
(53)(24)(43)(15)(10)(9)
Other balancing accounts77 158 (170)(51)247 209 
Other regulatory assets, net(3)
102 164 71 87 31 79 
Total$767 $39 $(262)$(736)$1,005 $707 
(1)    At September 30, 2025, $47 is classified as Assets Held for Sale on the Sempra Condensed Consolidated Balance Sheet.
(2)    At September 30, 2025 and December 31, 2024, the noncurrent portion of regulatory balancing accounts – net undercollected for Sempra is $1,627 and $1,731, respectively, for SDG&E is $990 and $873, respectively, and for SoCalGas is $637 and $858, respectively.
(3)    Includes regulatory assets earning a return authorized by applicable regulators, which generally approximates the three-month commercial paper rate.
In July 2025, the CPUC issued an FD that authorizes partial recovery of costs recorded in SoCalGas’ Catastrophic Event Memorandum Account. The FD authorizes the recovery of $19 million out of the requested $55 million, denying recovery of COVID-19 costs included in the Catastrophic Event Memorandum Account. In the nine months ended September 30, 2025, SoCalGas recorded a write-off of $36 million ($25 million after tax) in disallowed costs, comprising a $29 million reduction in Utilities: Natural Gas Revenues and a $7 million reduction in regulatory interest in Other (Expense) Income, Net, on Sempra’s and SoCalGas’ Condensed Consolidated Statements of Operations. SoCalGas has filed a request with the CPUC for a rehearing of the FD. SoCalGas expects to receive a post-rehearing FD in the first half of 2026.
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CPUC GRC
The CPUC uses GRCs to set base 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 capital investments. In December 2024, the CPUC approved an FD in the 2024 GRC for SDG&E and SoCalGas that authorizes SDG&E’s and SoCalGas’ revenue requirements for 2024 and attrition year adjustments for 2025 through 2027, inclusively.
The GRC FD adopts a 2024 revenue requirement of $2,699 million for SDG&E’s combined operations ($2,193 million for its electric operations and $506 million for its natural gas operations). SDG&E’s authorized 2024 combined revenue requirement represents an increase of $189 million (7.5%) over its authorized 2023 combined revenue requirement. In connection with SDG&E’s election to change its tax accounting method for gas repairs expenditures, the 2024 combined revenue requirement increase is net of $68 million of income tax benefits for 2023 and 2024 to be flowed through to customers. The GRC FD also specifies an increase in SDG&E’s 2025, 2026, and 2027 combined revenue requirements of $147 million (5.45%), $119 million (4.17%) and $122 million (4.11%), respectively, over the preceding year’s combined revenue requirement. The 2025, 2026 and 2027 revenue requirements will be updated to implement the applicable authorized changes in the cost of capital, which we describe below.
The GRC FD adopts a 2024 revenue requirement of $3,806 million for SoCalGas. SoCalGas’ authorized 2024 revenue requirement represents an increase of $324 million (9.3%) over its authorized 2023 revenue requirement. In connection with SoCalGas’ election to change its tax accounting method for gas repairs expenditures, the 2024 revenue requirement increase is net of $202 million of income tax benefits for 2023 and 2024 to be flowed through to customers. The GRC FD also specifies an increase in SoCalGas’ 2025, 2026, and 2027 revenue requirements of $190 million (5.00%), $116 million (2.91%) and $120 million (2.92%), respectively, over the preceding year’s revenue requirement. The 2025, 2026 and 2027 revenue requirements will be updated to implement the applicable authorized changes in the cost of capital, which we describe below.
Since the GRC FD was effective retroactive to January 1, 2024, SDG&E and SoCalGas recorded the retroactive impacts in the fourth quarter of 2024.
The GRC provides SDG&E and SoCalGas with numerous mechanisms to seek cost recovery of specified projects and programs. We expect that the requests for cost recovery of these projects and programs, which remain subject to CPUC approval, may result in additional amounts of authorized revenue requirement that are not included in the amounts described above.
2024 GRC Track 2
In October 2023, SDG&E submitted a separate request to the CPUC in its 2024 GRC, known as a Track 2 request. This request seeks review and recovery of $1.5 billion of wildfire mitigation plan costs incurred from 2019 through 2022 that were in addition to amounts authorized in the 2019 GRC and not addressed in the 2024 GRC FD. SDG&E expects to receive a proposed decision for its Track 2 request by the end of 2025.
Revenue requirements associated with the Track 2 request have been recorded in a regulatory account. In February 2024, the CPUC approved an interim cost recovery mechanism that permits SDG&E to recover in rates $194 million and $96 million of this regulatory account balance in 2024 and 2025, respectively. Such recovery of SDG&E’s wildfire mitigation plan regulatory account balance will be subject to refund, contingent on the reasonableness review decision for its Track 2 request.
2024 GRC Track 3
In April 2025, SDG&E and SoCalGas each submitted additional requests to the CPUC in the 2024 GRC, known as Track 3 requests. SDG&E submitted a request seeking review and recovery of $417 million of its wildfire mitigation plan costs incurred in 2023 that were in addition to the amounts authorized in the 2019 GRC and not addressed in the 2024 GRC. Additionally, SDG&E and SoCalGas submitted a combined request seeking review and recovery of $240 million and $499 million, respectively, of PSEP costs incurred from 2014 through 2019 and 2015 through 2020, respectively. SDG&E and SoCalGas expect to receive proposed decisions for their Track 3 requests in the first half of 2026.
Revenue requirements associated with the Track 3 requests have been recorded in regulatory accounts. SDG&E and SoCalGas are authorized interim rate recovery of up to 50% of the recorded PSEP regulatory account balance at the end of each year. Such interim rate recovery is subject to refund, contingent on the reasonableness review decision for their Track 3 requests.
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CPUC COST OF CAPITAL
A CPUC cost of capital proceeding every three years determines a utility’s authorized capital structure and authorized return on rate base. The CCM applies in the interim years 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 1.00% for 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 20% of the difference between the CCM benchmark rate and the applicable Moody’s utility bond index, subject to regulatory approval. Alternatively, SDG&E and SoCalGas are each permitted to file a cost of capital application to have its cost of capital determined in lieu of the CCM 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.
The following table summarizes the CPUC-approved cost of capital for SDG&E and SoCalGas. The authorized weighting remained unchanged for each of the years presented.
AUTHORIZED COST OF CAPITAL
Authorized weighting2024202520242025
Return on rate baseWeighted return on rate base
SDG&E:
Long-Term Debt45.25 %4.34 %4.34 %1.96 %1.96 %
Preferred Equity2.75 6.22 6.22 0.17 0.17 
Common Equity52.00 10.65 10.23 5.54 5.32 
100.00 %7.67 %7.45 %
SoCalGas:
Long-Term Debt45.60 %4.54 %4.63 %2.07 %2.11 %
Preferred Equity2.40 6.00 6.00 0.14 0.14 
Common Equity52.00 10.50 10.08 5.46 5.24 
100.00 %7.67 %7.49 %
In March 2025, SDG&E and SoCalGas each filed applications with the CPUC seeking to update their cost of capital for 2026 through 2028, subject to the CCM. SDG&E and SoCalGas expect to receive an FD by the end of 2025.
PROPOSED COST OF CAPITAL FOR 2026 – 2028
SDG&ESoCalGas
Authorized weightingReturn on
rate base		Weighted
return on
rate base		Authorized weightingReturn on
rate base		Weighted
return on
rate base
46.00 %4.62 %2.13 %Long-Term Debt45.60 %5.02 %2.29 %
— 6.22 — Preferred Equity2.40 6.00 0.14 
54.00 11.25 6.08 Common Equity52.00 11.00 5.72 
100.00 %8.21 %100.00 %8.15 %
FERC RATE MATTERS
SDG&E files separately with the FERC for its authorized transmission revenue requirement and ROE on FERC-regulated electric transmission operations and assets.
TO5 Settlement
SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision had been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019.
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TO6 Filing
In October 2024, SDG&E submitted its TO6 filing to the FERC and requested it to be effective January 1, 2025. SDG&E’s TO6 filing proposes, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing, subject to refund; suspended the effective date to June 1, 2025; established hearing and settlement judge procedures; and disallowed the inclusion of the California ISO adder, the last of which SDG&E has appealed.
NOTE 5. SEMPRA – INVESTMENTS IN UNCONSOLIDATED ENTITIES
We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. Equity earnings and losses, both before and net of income tax, are combined and presented as Equity Earnings on the Condensed Consolidated Statements of Operations. Distributions received from equity method investees are classified in the Condensed Consolidated Statements of Cash Flows as either a return on investment in operating activities or a return of investment in investing activities based on the “nature of the distribution” approach. See Note 14 for information on equity earnings and losses, both before and net of income tax, by segment. See Note 1 for information on how equity earnings and losses before income taxes are factored into the calculations of our pretax income or loss and ETR.
We provide additional information concerning our equity method investments in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
SEMPRA TEXAS UTILITIES
Oncor Holdings
We account for our 100% equity ownership interest in Oncor Holdings, which owns an 80.25% interest in Oncor, as an equity method investment. Due to the ring-fencing measures, governance mechanisms and commitments in effect, we do not have the power to direct the significant activities of Oncor Holdings and Oncor. See Note 5 of the Notes to Consolidated Financial Statements in the Annual Report for additional information related to the restrictions on our ability to direct the significant activities of Oncor Holdings and Oncor.
In the nine months ended September 30, 2025 and 2024, Sempra contributed $1.5 billion and $578 million, respectively, to Oncor Holdings, and Oncor Holdings distributed $459 million and $314 million, respectively, to Sempra. On October 29, 2025, Sempra contributed $519 million to Oncor Holdings, and on October 28, 2025, Oncor Holdings distributed $175 million to Sempra.
We provide summarized income statement information for Oncor Holdings in the following table.
SUMMARIZED FINANCIAL INFORMATION – ONCOR HOLDINGS
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
2025202420252024
Operating revenues$1,845 $1,660 $5,047 $4,610 
Operating expenses(1,213)(1,109)(3,537)(3,203)
Income from operations632 551 1,510 1,407 
Interest expense(201)(170)(578)(481)
Income tax expense(82)(75)(179)(179)
Net income378 320 814 791 
NCI held by Texas Transmission Investment LLC(75)(63)(162)(157)
Earnings attributable to Sempra(1)
303 257 652 634 
(1)    Excludes adjustments to equity earnings related to amortization of a tax sharing liability associated with a tax sharing agreement and changes in basis differences in AOCI within the carrying value of our equity method investment.
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SEMPRA INFRASTRUCTURE
In connection with the planned sale of a portion of our equity interest in SI Partners, which we discuss in Note 6, the carrying amount of our equity method investments totaling $2.5 billion at September 30, 2025 is included in Assets Held for Sale on Sempra’s Condensed Consolidated Balance Sheet.
Cameron LNG JV
In the nine months ended September 30, 2025 and 2024, Sempra Infrastructure contributed $2 million and $10 million, respectively, to Cameron LNG JV, and Cameron LNG JV distributed $369 million and $353 million, respectively, to Sempra Infrastructure.
TAG Norte
In the nine months ended September 30, 2025 and 2024, TAG Norte distributed $45 million and $62 million, respectively, to Sempra Infrastructure.
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NOTE 6. SEMPRA – POTENTIAL DIVESTITURES
SEMPRA INFRASTRUCTURE
Assets Held for Sale
We classify assets as held for sale once all applicable criteria under U.S. GAAP have been satisfied, including when management, having the authority to approve the action, commits to a formal plan to actively market an asset for sale and expects the sale to close within the next twelve months. Upon classifying a group of assets as held for sale, we record the disposal group at the lower of its carrying value or its estimated fair value reduced for selling costs, and we stop recording depreciation and amortization expense on those assets.
We summarize the carrying amounts of the major classes of assets and related liabilities of SI Partners, inclusive of Ecogas, classified as held for sale in the following table.
ASSETS HELD FOR SALE
(Dollars in millions)
September 30, 2025
Cash and cash equivalents
$126 
Restricted cash, current
2,889 
Accounts receivable
589 
Due from unconsolidated affiliates3 
Inventories103 
Other current assets
246 
Restricted cash, noncurrent
3 
Right-of-use assets – operating leases202 
Equity method investments
2,471 
Goodwill1,602 
Other intangible assets
273 
Other long-term assets
768 
Property, plant and equipment, net19,190 
Total assets held for sale$28,465 
Short-term debt$897 
Accounts payable
1,247 
Current portion of long-term debt49 
Other current liabilities
305 
Long-term debt6,791 
Due to unconsolidated affiliates
417 
Deferred income taxes901 
Asset retirement obligations93 
Deferred credits and other
475 
Total liabilities held for sale
$11,175 
At September 30, 2025, $28 million of accumulated losses is included in AOCI and is part of the disposal group that is held for sale.
We considered the estimated fair value of our assets held for sale, less costs to sell, and determined that no adjustment to carrying value was required. In estimating fair value, we used a discounted cash flow valuation technique. In the event that the estimated sales price, less transaction costs, is less than the carrying value, or updated market information indicates fair value may be less than carrying value, we would recognize a loss in our results of operations at that time.
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SI Partners
In September 2025, we entered into an agreement to sell 45% of the outstanding Class A Units and all general partner interests in SI Partners to the KKR Partners for an aggregate base purchase price of approximately $9.99 billion, subject to the adjustments described below. SI Partners owns LNG and natural gas infrastructure in the U.S. and Mexico and renewable energy and related assets in Mexico.
Subject to adjustments, the purchase price will be paid to Sempra as follows:
▪$4.65 billion in cash at closing;
▪$4.14 billion plus interest compounded quarterly at 7.5% per annum (totaling $4.72 billion with principal and accrued interest unless paid early) due December 31, 2027 under instruments backed by equity commitment letters; and
▪$1.2 billion plus interest compounded quarterly at 8.5% per annum before January 1, 2031 and 10.0% per annum thereafter (totaling $2.29 billion with principal and accrued interest unless paid early) due seven years and 91 days after closing under promissory notes.
The instruments and notes will be issued by indirect equity holders of the KKR Partners and will be ranked behind senior debt incurred by subsidiaries of the issuers.
The purchase price is subject to adjustments for changes in net debt, net working capital and capital expenditures as of December 31, 2025, among others. The purchase price is subject to further adjustments for certain capital contributions by and distributions to Sempra in 2026 before the closing. In addition, transaction fees of the KKR Partners of $337.5 million will be deducted from the purchase price at the closing and a development credit of $340 million will be payable by Sempra over two years starting in 2026. There may also be post-closing purchase price adjustments based on the performance through 2028 of certain wind power facilities, and an adjustment payable by Sempra for capital expenditures related to the ECA LNG Phase 1 project under construction.
We expect the sale to close in the second or third quarter of 2026, subject to expiration of the waiting period under the Hart-Scott-Rodino Act; receipt of applicable regulatory approvals, such as antitrust approvals in Mexico and approval by the FERC; receipt of certain other third-party consents or waivers; the absence of a material adverse effect on SI Partners; the absence of specific downgrade events under certain financing arrangements; and other customary closing conditions. Because the closing cannot occur before March 31, 2026, a ticking fee payable to Sempra of 0.625% per month on the aggregate base purchase price will accrue daily beginning April 1, 2026. If the KKR Partners fail to complete the closing when all closing conditions are satisfied, Sempra will receive a termination fee of $414 million. Any party may terminate the agreement if the closing has not occurred within 12 months after signing.
Subject to closing, the KKR Partners will own 65% of SI Partners, Sempra will retain a 25% interest and ADIA will retain a 10% interest. As we discuss below, the KKR Partners will have control of SI Partners and Sempra and ADIA will have certain minority rights in SI Partners. As a result of our loss of control upon completion of the sale, we will deconsolidate SI Partners and account for our 25% interest in SI Partners under the equity method within the existing Sempra Infrastructure segment.
In connection with signing the agreement for the sale, in September 2025, we classified SI Partners as held for sale, ceased recording depreciation and amortization, and recognized $514 million in Income Tax Expense on Sempra’s Condensed Consolidated Statements of Operations to (i) adjust deferred income tax liabilities related to outside basis differences in our investment in SI Partners, (ii) account for changes to state income tax apportionment, and (iii) account for valuation allowances against certain tax credit carryforwards. The amount of this charge is based on certain assumptions and could change substantially in subsequent quarters and at the closing due to, among other things, changes to current carrying values, changes in forecasted taxable income, purchase price adjustments, and changes to tax positions and other assumptions.
Post-Closing Limited Partnership Agreement. At closing, we will enter into an amended and restated limited partnership agreement with the KKR Partners and ADIA. The limited partnership agreement provides that the KKR Partners will have the right to appoint four managers, Sempra will have the right to appoint two managers, and ADIA will have the right to appoint one manager to the SI Partners board of managers, with matters decided by majority vote based on the limited partners’ ownership percentages. The minority partners will have certain minority consent rights so long as they maintain specified ownership thresholds. Subject to exceptions and limitations, SI Partners will be prohibited from taking certain actions, including, among others: (i) redeeming units or making distributions to its limited partners other than on a pro rata basis or as expressly permitted under the partnership agreement; (ii) under certain circumstances, transferring, disposing or issuing equity securities in any subsidiary undertaking or owning a project that has reached a positive FID; (iii) appointing a replacement chief executive officer; (iv) approving certain capital expenditures; and (v) reaching a positive FID on any project, in each case without prior approval from KKR, Sempra and, in some cases, other limited partners holding at least a specified minimum percentage of ownership.
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SI Partners will be required to distribute quarterly at least 85% of its distributable cash flow, subject to certain exceptions and reserves. Generally, distributions will be made to the limited partners on a pro rata basis in accordance with their respective ownership interests, except that the KKR Partners will be entitled to a post-closing distribution of an additional 31.5% of the $1.9 billion true-up payment from Port Arthur LNG II to Port Arthur LNG I to acquire a 50% interest in the shared common facilities. The limited partners will be required to fund capital calls under certain circumstances, which vary depending on whether a project has reached positive FID. Sempra will continue to have substantially similar funding obligations as it has before the sale for cost overruns in certain projects, including the ECA LNG Phase 1 project and the PA LNG Phase 1 project.
If a project fails to receive the required limited partner approvals to achieve FID, the KKR Partners will be permitted to proceed with the project independently through a different investment vehicle or as a “Sole Risk Project” within SI Partners in exchange for “Sole Risk Interests.” Sole Risk Projects are separated from other SI Partners projects and are conducted at the holder’s sole cost, expense and liability, and the holder receives, through the acquisition of Sole Risk Interests, the economic and other benefits, if any, from such projects. The Guaymas-El Oro segment of the Sonora pipeline will continue to be owned by and a Sole Risk Project of Sempra. Sempra is solely responsible for costs associated with the pipeline and any proceeds from a sale of the pipeline would be split between Sempra (90%) and ADIA (10%), subject to adjustments.
Under the limited partnership agreement, Sempra will be restricted from transferring its ownership interest in SI Partners before January 1, 2029. Any proposed transfer (other than a permitted transfer) by a minority partner to a third party will be subject to a right of first offer of the KKR Partners. The minority partners will have co-sale rights in respect of any transfer by the KKR Partners of over 50% of SI Partners’ equity interests. The KKR Partners will have customary drag-along rights in connection with any sale of SI Partners, provided that the minority partners obtain minimum return thresholds. The limited partners have customary registration rights in the event of an initial public offering of SI Partners.
Ecogas
In June 2025, management committed to a formal plan to market and sell Ecogas, a natural gas regulated distribution utility that operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. We expect to complete the sale in the second or third quarter of 2026. As a result of satisfying all applicable criteria, we classified Ecogas’ assets and liabilities as held for sale and ceased depreciation and amortization.
In connection with classifying Ecogas as held for sale, we recognized $38 million in Income Tax Expense on Sempra’s Condensed Consolidated Statement of Operations in the nine months ended September 30, 2025 for a Mexican deferred income tax liability related to the excess of carrying value over the tax basis (outside basis difference). Since this $38 million ($26 million after NCI) of Mexican income tax expense on our outside basis difference is based on current carrying value, foreign exchange rates and inflation at September 30, 2025, this amount could change in future periods until the date of sale.
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NOTE 7. DEBT AND CREDIT FACILITIES
The principal terms of our debt arrangements are described below and in Note 6 of the Notes to Consolidated Financial Statements in the Annual Report.
SHORT-TERM DEBT
Committed Lines of Credit
At September 30, 2025, Sempra had an aggregate capacity of $10.2 billion under eight 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.
COMMITTED LINES OF CREDIT
(Dollars in millions)
September 30, 2025
BorrowerExpiration date of facilityTotal facilityCommercial paper outstandingAmounts outstandingLetters of credit outstandingAvailable unused credit
Sempra
October 2030(1)
$4,000 $(146)$— $— $3,854 
SDG&E
October 2030(1)
1,500 (27)— — 1,473 
SoCalGas
October 2030(1)
1,200 (411)— — 789 
SI Partners and IEnovaAugust 20261,000 — — — 1,000 
SI Partners and IEnova
September 2026(2)
500 — (396)— 104 
SI Partners and IEnovaAugust 20281,500 — (491)— 1,009 
Port Arthur LNG IMarch 2030200 — — (87)113 
Port Arthur LNG IISeptember 2030300 — — (100)200 
Total$10,200 $(584)$(887)$(187)$8,542 
(1)     In October 2025, Sempra, SDG&E and SoCalGas each amended their respective credit facility to extend the expiration date from October 2029 to October 2030.
(2)     In September 2025, SI Partners and IEnova amended their shared credit facility to extend the expiration date from September 2025 to September 2026.
Sempra, SDG&E and SoCalGas each must maintain a ratio of indebtedness to total capitalization (as defined in each of the applicable credit facilities) of no more than 65% at the end of each quarter. At September 30, 2025, each Registrant was in compliance with this ratio under its respective credit facility.
The three lines of credit that are shared by SI Partners and its subsidiary, IEnova, require that SI Partners maintain a ratio of consolidated adjusted net indebtedness to consolidated earnings before interest, taxes, depreciation and amortization (as defined in each credit facility) of no more than 5.25 to 1.00 at the end of each quarter. At September 30, 2025, SI Partners was in compliance with this ratio.
In September 2025, Port Arthur LNG II entered into a working capital facility agreement, reflected in the table above, that permits borrowings of up to $300 million, which bear interest by reference to term SOFR, plus the applicable margin and a credit adjustment spread. The credit facility also provides for the issuance of up to $300 million of letters of credit, which reduces available unused credit. SI Partners has provided a guarantee for repayment of the $300 million credit facility supporting construction of the PA LNG Phase 2 project.
Additionally, the three lines of credit that are shared by SI Partners and IEnova and the Port Arthur LNG I and Port Arthur LNG II credit facilities are included in the held for sale disposal group that we discuss in Note 6 but remain legally accessible and a source of available credit to Sempra Infrastructure until the sale of a portion of our equity interest in SI Partners closes.
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Uncommitted Line of Credit
ECA LNG Phase 1 has an uncommitted line of credit with an aggregate capacity of $100 million that expires in August 2026. Borrowings are generally used for working capital requirements and can be in U.S. dollars or Mexican pesos. At September 30, 2025, ECA LNG Phase 1 had outstanding borrowings of $10 million, before reductions of any unamortized discounts, in Mexican pesos that bear interest at a variable rate based on the 28-day Interbank Equilibrium Interest Rate plus 154 bps. Borrowings made in U.S. dollars bear interest at a variable rate based on the one-month or three-month SOFR plus 164 bps and a credit adjustment spread of 10 bps.
Uncommitted Letters of Credit
Outside of our domestic and foreign credit facilities, we have unsecured standby letter of credit capacity with select lenders that is uncommitted and supported by reimbursement agreements. At September 30, 2025, we had $2.0 billion in standby letters of credit outstanding under these agreements.
UNCOMMITTED LETTERS OF CREDIT OUTSTANDING
(Dollars in millions)
Expiration date rangeSeptember 30, 2025
SDG&EJanuary 2026 - November 2026$21 
SoCalGasMarch 2026 - December 202615 
Other SempraOctober 2025 - November 20541,948 
Total Sempra$1,984 
In September 2025, SI Partners entered into a $1.5 billion unsecured standby letter of credit agreement, reflected in the table above, to support construction of the PA LNG Phase 2 project. The available capacity is subject to reduction as construction progresses and milestones are completed.
Term Loans
SoCalGas
In May 2024, SoCalGas entered into a $500 million, 364-day term loan facility with a maturity date of May 22, 2025, and in December 2024, SoCalGas increased the amount of the term loan to $700 million. SoCalGas borrowed the full $700 million available under the term loan, net of negligible debt issuance costs. The borrowings bore interest at a per annum rate equal to term SOFR, plus 80 bps and a credit adjustment spread of 10 bps. SoCalGas used the proceeds to repay commercial paper and for other general corporate purposes. SoCalGas repaid the term loan in full in May 2025, at which time the term loan facility ceased to be in effect.
Other Sempra
In May 2025, Sempra entered into a $1.25 billion, 364-day term loan facility with a maturity date of 364 days from the initial borrowing date. On July 28, 2025, Sempra borrowed the full $1.25 billion available under the term loan. Sempra was permitted to request an increase in the term loan facility of up to $500 million prior to the maturity date, subject to lender approval, which it requested, received and borrowed in full in October 2025. The borrowings bear interest at a per annum rate equal to term SOFR, plus 80 bps and a credit adjustment spread of 10 bps. Sempra used the proceeds for working capital, capital expenditures, other general corporate purposes and to pay a portion of the cost to redeem all outstanding shares of Sempra’s series C preferred stock.
Weighted-Average Interest Rates
The weighted-average interest rates on all short-term debt are as follows:
WEIGHTED-AVERAGE INTEREST RATES
September 30, 2025December 31, 2024
Sempra4.84 %5.03 %
SDG&E4.24 4.76 
SoCalGas4.26 5.02 
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LONG-TERM DEBT
SDG&E
In March 2025, SDG&E issued $850 million aggregate principal amount of 5.40% first mortgage bonds due in full upon maturity on April 15, 2035 and received proceeds of $840 million (net of debt discount, underwriting discounts and debt issuance costs of $10 million). The first mortgage bonds are redeemable prior to maturity, subject to their terms, and in certain circumstances subject to make-whole provisions. SDG&E used the net proceeds for general corporate purposes, including repayment of outstanding commercial paper and other indebtedness.
SoCalGas
In May 2025, SoCalGas issued $600 million aggregate principal amount of 5.45% first mortgage bonds due in full upon maturity on June 15, 2035 and received proceeds of $592 million (net of debt discount, underwriting discounts and debt issuance costs of $8 million), and $500 million aggregate principal amount of 6.00% first mortgage bonds due in full upon maturity on June 15, 2055 and received proceeds of $488 million (net of debt discount, underwriting discounts, and debt issuance costs of $12 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. SoCalGas used the net proceeds to repay outstanding indebtedness and for other general corporate purposes.
Other Sempra
Sempra
In August 2025, Sempra issued $800 million aggregate principal amount of 6.375% fixed-to-fixed reset rate junior subordinated notes maturing on April 1, 2056. Interest on the notes accrues from and including August 29, 2025 and is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on April 1, 2026. The notes bear interest (i) from and including August 29, 2025 to, but excluding, April 1, 2031 at the rate of 6.375% per annum and (ii) from and including April 1, 2031, during each subsequent five-year period beginning on April 1 of every fifth year, at a rate per annum equal to the Five-year U.S. Treasury Rate (as defined in the notes) as of the day falling two business days before the first day of such five-year period plus a spread of 2.632%, to be reset on April 1 of every fifth year beginning in 2031; provided that the interest rate during any such five-year period will not reset below 6.375% per annum. We received proceeds of $791 million (net of underwriting discounts and debt issuance costs of $9 million). We used the proceeds from the offering to pay a portion of the cost to redeem all outstanding shares of Sempra’s series C preferred stock.
We may redeem some or all of the notes before their maturity, as follows:
▪in whole or in part, (i) on any day in the period commencing on the date falling 90 days prior to, and ending on and including April 1, 2031 and (ii) after April 1, 2031, on any interest payment date, at a redemption price in cash equal to 100% of the principal amount of the notes being redeemed, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to be redeemed to, but excluding, the redemption date;
▪in whole but not in part, at any time following the occurrence and during the continuance of a tax event (as defined in the notes) at a redemption price in cash equal to 100% of the principal amount of the notes, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to, but excluding, the redemption date; and
▪in whole but not in part, at any time following the occurrence and during the continuance of a rating agency event (as defined in the notes) at a redemption price in cash equal to 102% of the principal amount of the notes, plus, subject to the terms of the notes, accrued and unpaid interest on the notes to, but excluding, the redemption date.
The notes are unsecured obligations and rank junior and subordinate in right of payment to our existing and future senior indebtedness. The notes rank equally in right of payment with our existing 4.125% fixed-to-fixed reset rate junior subordinated notes due 2052, 6.40% fixed-to-fixed reset rate junior subordinated notes due 2054, 6.875% fixed-to-fixed reset rate junior subordinated notes due 2054, 6.55% fixed-to-fixed reset rate junior subordinated notes due 2055, 6.625% fixed-to-fixed reset rate junior subordinated notes due 2055, and 5.75% junior subordinated notes due 2079 and with any future unsecured indebtedness that we may incur if the terms of such indebtedness provide that it ranks equally with the notes in right of payment. The notes are effectively subordinated in right of payment to any secured indebtedness we have incurred or may incur (to the extent of the value of the collateral securing such secured indebtedness) and to all existing and future indebtedness and other liabilities and any preferred equity of our subsidiaries.
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ECA LNG Phase 1
ECA LNG Phase 1 has a loan agreement with a syndicate of external lenders that was set to mature on December 9, 2025 for an aggregate principal amount of up to $1.3 billion. In July 2025, ECA LNG Phase 1 amended this loan agreement to extend the maturity date to December 30, 2027 and increase the aggregate borrowing capacity to $1.5 billion. The modified loan agreement bears interest at a weighted-average blended rate of 2.29% plus a benchmark interest rate per annum equal to (a) term SOFR based on a tenor comparable to the applicable interest period, plus (b) a credit adjustment spread of 10 bps.
IEnova and TotalEnergies SE have provided guarantees for repayment of the loan of up to $1,226 million and $305 million, respectively, plus accrued and unpaid interest. The effective interest rate of the loan is based on the interest payments made to external lenders and guarantee payments made to TotalEnergies SE as a guarantor.
At September 30, 2025 and December 31, 2024, $1.2 billion and $1.1 billion, respectively, of borrowings from external lenders were outstanding under the loan agreement, with a weighted-average interest rate of 6.39% and 7.29%, respectively. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project.
Port Arthur LNG I
Port Arthur LNG I has a seven-year term loan facility agreement with a syndicate of lenders that matures on March 20, 2030 for an aggregate principal amount of approximately $6.8 billion. At September 30, 2025 and December 31, 2024, $2.2 billion and $1.1 billion, respectively, of borrowings were outstanding under the loan agreement, with an all-in weighted-average interest rate of 5.46% and 5.33%, respectively. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.
In January 2025, Port Arthur LNG I issued senior secured notes for an aggregate principal amount of $750 million and received proceeds of $742 million (net of debt issuance costs of $8 million). In April 2025, Port Arthur LNG I issued senior secured notes for an aggregate principal amount of $250 million and received proceeds of $248 million (net of debt issuance costs of $2 million). The notes issued in January 2025 and April 2025 bear interest at the rate of 6.27% and 6.32%, respectively, and mature in December 2042. The net proceeds were used to repay borrowings and accrued interest under the existing Port Arthur LNG I term loan facility.
NOTE 8. DERIVATIVE FINANCIAL INSTRUMENTS
We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that could cause our asset values to fall or our liabilities to increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.
In certain cases, we apply the normal purchase or sale exception to contracts that otherwise would have been accounted for as 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 Condensed 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 (1) principal settlements of cross-currency swaps that hedge exposure related to Mexican peso-denominated debt and amounts related to terminations or early settlements of interest rate swaps as financing activities, (2) principal settlements of interest rate swaps associated with capitalized interest costs incurred to finance capital projects as investing activities, and (3) settlements of other derivative instruments as operating activities on the Condensed Consolidated Statements of Cash Flows.
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HEDGE ACCOUNTING
We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk of variability of future cash flows of a given revenue or expense item, 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. 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. 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 Condensed 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 Condensed 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 these undesignated derivatives are recognized in Energy-Related Businesses Revenues on the Condensed Consolidated Statements of Operations.
▪Sempra Infrastructure may use natural gas derivatives when supplying feed gas to its LNG liquefaction facilities to support the production of LNG. Gains and losses from these undesignated derivatives are recognized in Energy-Related Businesses Cost of Sales on the Condensed Consolidated Statements of Operations.
▪From time to time, our various businesses, including SDG&E and SoCalGas, may use other derivatives to hedge exposures such as GHG allowances.
The following table summarizes net energy derivative volumes.
NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
CommodityUnit of measureSeptember 30, 2025December 31, 2024
Sempra:
Natural gasMMBtu1,405 637 
Congestion revenue rightsMWh20 27 
SDG&E:
Natural gasMMBtu17 16 
Congestion revenue rightsMWh20 27 
SoCalGas:
Natural gasMMBtu415 347 
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INTEREST RATE DERIVATIVES
We are exposed to interest rates primarily as a result of our current and expected use of financing. SDG&E and SoCalGas, as well as Sempra and its other subsidiaries and equity method investees, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.
The following table presents the notional amounts of our interest rate derivatives, excluding those in our equity method investments.
INTEREST RATE DERIVATIVES
(Dollars in millions)
 September 30, 2025December 31, 2024
 Notional amountMaturitiesNotional amountMaturities
Sempra:    
Cash flow hedges$258 2025-2034$271 2025-2034
Undesignated derivatives(1)
3,189 2025-20483,189 2025-2048
(1)    At September 30, 2025 and December 31, 2024, undesignated derivatives accrued interest based on a notional amount of $1,876 and $1,598, respectively.
FOREIGN CURRENCY DERIVATIVES
From time to time, Sempra Infrastructure and its equity method investees may use 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. Oncor uses cross-currency swaps designated as fair value hedges intended to offset foreign currency exchange rate risk related to its Euro and Canadian dollar denominated debt.
We are also exposed to exchange rate movements at our Mexican subsidiaries and equity method investees, 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.
The following table presents the notional amounts of our foreign currency derivatives, excluding those in our equity method investments.
FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
 September 30, 2025December 31, 2024
 Notional amountMaturitiesNotional amountMaturities
Sempra:    
Foreign currency derivatives$158 2025-2027$162 2025-2026
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FINANCIAL STATEMENT PRESENTATION
The Condensed 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 Condensed Consolidated Balance Sheets, including the amount of cash collateral receivables that were not offset because the cash collateral was in excess of liability positions. We discuss the fair value of derivative assets and liabilities in Note 9.
DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 September 30, 2025
Current assetsCurrent liabilities
 
Fixed-price contracts and other derivatives(1)
Assets
held for sale
Other long-term assetsOther current
liabilities		Liabilities held for saleDeferred credits and other
Sempra:
    
Derivatives designated as hedging instruments:    
Interest rate instruments$25 $— 
Foreign exchange instruments— (5) 
Derivatives not designated as hedging instruments:    
Interest rate instruments189 — 
Commodity contracts not subject to rate recovery24 (63)
Associated offsetting commodity contracts(5)5 
Commodity contracts subject to rate recovery$6 $11 $(127)$(13)
Associated offsetting commodity contracts(3)(4)3 4 
Associated offsetting cash collateral— — 52 3 
Net amounts presented on the balance sheet3 233 7 (72)(63)(6)
Additional cash collateral for commodity contracts
not subject to rate recovery
— 60 — — — — 
Additional cash collateral for commodity contracts
subject to rate recovery
32 — — — 
Total
$35 $293 $7 $(72)$(63)$(6)
SDG&E:    
Derivatives not designated as hedging instruments:    
Commodity contracts subject to rate recovery$2 $7 $(9)$(5)
Associated offsetting commodity contracts— (2)— 2 
Associated offsetting cash collateral— — 9 3 
Net amounts presented on the balance sheet2 5 — — 
Additional cash collateral for commodity contracts
subject to rate recovery
24 — — — 
Total
$26 $5 $— $— 
SoCalGas:    
Derivatives not designated as hedging instruments:    
Commodity contracts subject to rate recovery$4 $4 $(118)$(8)
Associated offsetting commodity contracts(3)(2)3 2 
Associated offsetting cash collateral— — 43 — 
Net amounts presented on the balance sheet1 2 (72)(6)
Additional cash collateral for commodity contracts
subject to rate recovery
8 — — — 
Total$9 $2 $(72)$(6)
(1)    Included in Other Current Assets for SDG&E and SoCalGas.
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DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
 December 31, 2024
Current assets: Fixed-price contracts and other derivatives(1)
Other long-term assetsOther current liabilitiesDeferred credits and other
Sempra:    
Derivatives designated as hedging instruments:    
Interest rate instruments$7 $28 $— $— 
Foreign exchange instruments4 1 — — 
Derivatives not designated as hedging instruments:    
Interest rate instruments12 246 — — 
Commodity contracts not subject to rate recovery16 23 (21)(43)
Associated offsetting commodity contracts(15)(23)15 23 
Commodity contracts subject to rate recovery7 4 (55)(10)
Associated offsetting commodity contracts(5)(2)5 2 
Associated offsetting cash collateral— — 10 4 
Net amounts presented on the balance sheet26 277 (46)(24)
Additional cash collateral for commodity contracts
not subject to rate recovery
40 — — — 
Additional cash collateral for commodity contracts
subject to rate recovery
25 — — — 
Total(2)
$91 $277 $(46)$(24)
SDG&E:    
Derivatives not designated as hedging instruments:    
Commodity contracts subject to rate recovery$4 $4 $(13)$(6)
Associated offsetting commodity contracts(2)(2)2 2 
Associated offsetting cash collateral— — 10 4 
Net amounts presented on the balance sheet2 2 (1)— 
Additional cash collateral for commodity contracts
subject to rate recovery
21 — — — 
Total(2)
$23 $2 $(1)$— 
SoCalGas:    
Derivatives not designated as hedging instruments:    
Commodity contracts subject to rate recovery$3 $— $(42)$(4)
Associated offsetting commodity contracts(3)— 3 — 
Net amounts presented on the balance sheet— — (39)(4)
Additional cash collateral for commodity contracts
subject to rate recovery
4 — — — 
Total$4 $— $(39)$(4)
(1)    Included in Other Current Assets for SDG&E and SoCalGas.
(2)    Normal purchase contracts previously measured at fair value are excluded.
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The following table includes the effects of derivative instruments designated as hedges on the Condensed Consolidated Statements of Operations and in OCI and AOCI.
HEDGE IMPACTS
(Dollars in millions)
Pretax gain (loss)
recognized in OCI		Pretax gain (loss) reclassified
from AOCI into earnings
Three months ended September 30, Three months ended September 30,
 20252024Location20252024
Sempra:     
Cash flow hedges:
Interest rate instruments$2 $(203)Interest expense$4 $3 
Interest rate instruments(6)(33)
Equity earnings(1)
6 5 
Foreign exchange instruments(1)— 
Revenues: Energy-
related businesses
(2)— 
Foreign exchange instruments— 2 Other income, net(1)1 
Foreign exchange instruments(1)2 
Equity earnings(1)
(3)1 
Fair value hedges:
Foreign exchange instruments(5)(3)
Equity earnings(1)
— — 
Total$(11)$(235) $4 $10 
SoCalGas:
Cash flow hedges:
Interest rate instruments$— $— Interest expense$(1)$— 
 Nine months ended September 30, Nine months ended September 30,
 20252024Location20252024
Sempra:     
Cash flow hedges:
Interest rate instruments$(4)$5 Interest expense$6 $9 
Interest rate instruments(39)(8)
Equity earnings(1)
10 20 
Foreign exchange instruments(11)14 
Revenues: Energy-
related businesses
(3)5 
Other income, net(2)2 
Foreign exchange instruments(10)12 
Equity earnings(1)
(4)5 
Fair value hedges:
Foreign exchange instruments(30)(10)
Equity earnings(1)
— — 
Total$(94)$13  $7 $41 
SoCalGas:
Cash flow hedges:
Interest rate instruments$— $— Interest expense$(1)$(1)
(1)    Equity earnings at Oncor Holdings and our foreign equity method investees are recognized after tax.
For Sempra, we expect that net gains before NCI of $4 million, which are net of income tax expense, that are currently recorded in AOCI (with net gains of $3 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 $1 million of losses, net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next 12 months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates and foreign currency rates in effect when derivative contracts mature.
At September 30, 2025, the maximum length of time over which Sempra is hedging its exposure to the variability in future cash flows for forecasted transactions, excluding those forecasted transactions related to the payment of variable interest on existing financial instruments, is approximately one year.
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The following table summarizes the effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations.
UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
  Pretax (loss) gain on derivatives recognized in earnings
  Three months ended September 30,Nine months ended September 30,
 Location2025202420252024
Sempra:     
Commodity contracts not
subject to rate recovery
Revenues: Energy-related
businesses
$(35)$98 $4 $218 
Commodity contracts not
subject to rate recovery
Energy-related businesses
cost of sales
1 — (1)— 
Commodity contracts subject
to rate recovery
Cost of natural gas(91)(16)(111)(43)
Commodity contracts subject
to rate recovery
Cost of electric fuel and purchased power(7)(10)(3)(29)
Interest rate instrumentsInterest expense(2)— (58)— 
Total $(134)$72 $(169)$146 
SDG&E:     
Commodity contracts subject
to rate recovery
Cost of electric fuel and purchased power$(7)$(10)$(3)$(29)
SoCalGas:     
Commodity contracts subject
to rate recovery
Cost of natural gas$(91)$(16)$(111)$(43)
CREDIT RISK RELATED CONTINGENT FEATURES
For Sempra, SDG&E and SoCalGas, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.
For Sempra, the total fair value of this group of derivative instruments in a liability position at September 30, 2025 and December 31, 2024 is $227 million and $122 million, respectively. For SDG&E, the total fair value of this group of derivative instruments in a liability position is negligible at both September 30, 2025 and December 31, 2024. For SoCalGas, the total fair value of this group of derivative instruments in a liability position at September 30, 2025 and December 31, 2024 is $78 million and $42 million, respectively. At September 30, 2025, if the credit ratings of Sempra or SoCalGas were reduced below investment grade, $227 million, and $78 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.
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NOTE 9. FAIR VALUE MEASUREMENTS
We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
RECURRING FAIR VALUE MEASURES
The tables below set forth our financial assets and liabilities, by level within the fair value hierarchy, that were accounted for at fair value on a recurring basis at September 30, 2025 and December 31, 2024. 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. We have not changed the valuation techniques or types of inputs we use to measure recurring fair value since December 31, 2024.
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 at SDG&E, as we discuss below in “Level 3 Information – SDG&E.” We further discuss derivative assets and liabilities in Note 8.
▪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 13, 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 – Other Sempra.”
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RECURRING FAIR VALUE MEASURES
(Dollars in millions)
Level 1Level 2Level 3
Netting(1)
Total
Fair value at September 30, 2025
Sempra:
Assets:    
Nuclear decommissioning trusts:    
Short-term investments, primarily cash equivalents
$19 $2 $— $21 
Equity securities289 3 — 292 
Debt securities:    
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies
28 26 — 54 
Municipal bonds— 296 — 296 
Other securities— 254 — 254 
Total debt securities28 576 — 604 
Total nuclear decommissioning trusts(2)
336 581 — 917 
Short-term investments held in Rabbi Trust22 — — 22 
Support Agreement, net of related guarantee fees— — 39 39 
Commodity contracts subject to rate recovery3 8 6 $25 42 
Total
361 589 45 25 1,020 
Assets held for sale:
Interest rate instruments— 214 — — 214 
Commodity contracts not subject to rate recovery— 24 — 55 79 
Total assets held for sale
— 238 — 55 293 
Total assets
$361 $827 $45 $80 $1,313 
Liabilities:    
Commodity contracts subject to rate recovery$34 $106 $— $(62)$78 
Liabilities held for sale:
Foreign exchange instruments— 5 — — 5 
Commodity contracts not subject to rate recovery— 63 — (5)58 
Total liabilities held for sale— 68 — (5)63 
Total liabilities$34 $174 $— $(67)$141 
(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.
(2)    Excludes receivables (payables), net.
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RECURRING FAIR VALUE MEASURES
(Dollars in millions)
Level 1Level 2Level 3
Netting(1)
Total
Fair value at December 31, 2024
Sempra:
Assets:
Nuclear decommissioning trusts:
Short-term investments, primarily cash equivalents$8 $2 $— $10 
Equity securities295 3 — 298 
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies
41 26 — 67 
Municipal bonds— 287 — 287 
Other securities— 228 — 228 
Total debt securities41 541 — 582 
Total nuclear decommissioning trusts(2)
344 546 — 890 
Short-term investments held in Rabbi Trust64 — — 64 
Support Agreement, net of related guarantee fees— — 25 25 
Interest rate instruments— 293 — $— 293 
Foreign exchange instruments— 5 — — 5 
Commodity contracts not subject to rate recovery— 39 — 2 41 
Commodity contracts subject to rate recovery6 1 4 18 29 
Total$414 $884 $29 $20 $1,347 
Liabilities:
Commodity contracts not subject to rate recovery$1 $63 $— $(38)$26 
Commodity contracts subject to rate recovery20 45 — (21)44 
Total$21 $108 $— $(59)$70 
(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.
(2)    Excludes receivables (payables), net.
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RECURRING FAIR VALUE MEASURES
(Dollars in millions)
Level 1Level 2Level 3
Netting(1)
Total
Fair value at September 30, 2025
SDG&E:
Assets:    
Nuclear decommissioning trusts:    
Short-term investments, primarily cash equivalents
$19 $2 $— $21 
Equity securities289 3 — 292 
Debt securities:    
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies
28 26 — 54 
Municipal bonds— 296 — 296 
Other securities— 254 — 254 
Total debt securities28 576 — 604 
Total nuclear decommissioning trusts(2)
336 581 — 917 
Commodity contracts subject to rate recovery3 — 6 $22 31 
Total$339 $581 $6 $22 $948 
Liabilities:    
Commodity contracts subject to rate recovery$14 $— $— $(14)$— 
 Fair value at December 31, 2024
SDG&E:
Assets:    
Nuclear decommissioning trusts:    
Short-term investments, primarily cash equivalents
$8 $2 $— $10 
Equity securities295 3 — 298 
Debt securities:   
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies
41 26 — 67 
Municipal bonds— 287 — 287 
Other securities— 228 — 228 
Total debt securities41 541 — 582 
Total nuclear decommissioning trusts(2)
344 546 — 890 
Commodity contracts subject to rate recovery4 — 4 $17 25 
Total$348 $546 $4 $17 $915 
Liabilities:   
Commodity contracts subject to rate recovery$18 $1 $— $(18)$1 
(1)    Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)    Excludes receivables (payables), net.
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RECURRING FAIR VALUE MEASURES
(Dollars in millions)
Level 1Level 2Level 3
Netting(1)
Total
Fair value at September 30, 2025
SoCalGas:
Assets:    
Commodity contracts subject to rate recovery$— $8 $— $3 $11 
Liabilities:    
Commodity contracts subject to rate recovery$20 $106 $— $(48)$78 
 Fair value at December 31, 2024
SoCalGas:
Assets:    
Commodity contracts subject to rate recovery$2 $1 $— $1 $4 
Liabilities:    
Commodity contracts subject to rate recovery$2 $44 $— $(3)$43 
(1)    Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Level 3 Information
SDG&E
The table below sets forth reconciliations of changes in the fair value of CRRs classified as Level 3 in the fair value hierarchy for Sempra and SDG&E.
LEVEL 3 RECONCILIATIONS(1)
(Dollars in millions)
 Three months ended September 30,
 20252024
Balance at July 1$3 $6 
Realized and unrealized gains (losses), net3 (3)
Allocated transmission instruments2 1 
Settlements(2)2 
Balance at September 30$6 $6 
Change in unrealized gains (losses) relating to instruments still held at September 30
$2 $— 
Nine months ended September 30,
20252024
Balance at January 1$4 $10 
Realized and unrealized gains (losses), net1 (6)
Allocated transmission instruments5 1 
Settlements(4)1 
Balance at September 30$6 $6 
Change in unrealized gains (losses) relating to instruments still held at September 30
$(1)$(1)
(1)    Excludes the effect of the contractual ability to settle contracts under master netting agreements and cash collateral.

Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Because unrealized gains and losses are recorded as regulatory assets and liabilities, they do not affect earnings. Inputs used to determine the fair value of CRRs are reviewed and compared with market conditions to determine reasonableness.
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CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. Annual auction prices are published once a year, typically in the middle of November, and are the basis for valuing CRRs settling in the following year. For the CRRs settling from January 1 to December 31, the auction price inputs, at a given location, were in the following ranges for the years indicated below:
CONGESTION REVENUE RIGHTS AUCTION PRICE INPUTS
Settlement yearPrice per MWhMedian price per MWh
2025$(7.38)to$15.54 $0.01 
2024(3.69)to9.55 (0.44)
The impact associated with discounting is not significant. 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 8.
Other Sempra
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.
LEVEL 3 RECONCILIATIONS
(Dollars in millions)
Three months ended September 30,
 20252024
Balance at July 1$39 $23 
Realized and unrealized gains (losses), net(1)
2 3 
Settlements(2)(2)
Balance at September 30(2)
$39 $24 
Change in unrealized gains (losses) relating to instruments still held at September 30
$2 $3 
Nine months ended September 30,
20252024
Balance at January 1$25 $23 
Realized and unrealized gains (losses), net(1)
20 7 
Settlements(6)(6)
Balance at September 30(2)
$39 $24 
Change in unrealized gains (losses) relating to instruments still held at September 30
$20 $6 
(1)    Net gains are included in Interest Income and net losses are included in Interest Expense on Sempra’s Condensed Consolidated Statements of Operations.
(2)    Includes $8 in Other Current Assets and $31 in Other Long-Term Assets at September 30, 2025 on Sempra's Condensed Consolidated Balance Sheet.

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 A2 and A3 at September 30, 2025, and 2024, respectively, and relied on default rate data published by Moody’s to assign a probability of default. A hypothetical change in the credit rating up or down one notch would not result in a significant change in the fair value of the Support Agreement.
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Fair Value of Financial Instruments
The fair values of certain of our financial instruments (cash, current and noncurrent accounts receivable, amounts due to/from unconsolidated affiliates with original maturities of less than 90 days, dividends and accounts payable due in one year or less, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Condensed Consolidated Balance Sheets.
FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
 Carrying
amount		Fair value
 Level 1Level 2Level 3Total
September 30, 2025
Sempra:     
Long-term note receivable(1)
$364 $— $— $359 $359 
Long-term amounts due to unconsolidated affiliates held for sale417 — 400 — 400 
Long-term debt held for sale(2)
6,961 — 6,661 — 6,661 
Long-term debt(3)
29,866 — 28,376 — 28,376 
SDG&E:     
Long-term debt(4)
$9,800 $— $8,849 $— $8,849 
SoCalGas:     
Long-term debt(5)
$8,109 $— $7,847 $— $7,847 
 December 31, 2024
Sempra:     
Long-term note receivable(1)
$351 $— $— $334 $334 
Long-term amounts due to unconsolidated affiliates352 — 324 — 324 
Long-term debt(3)
32,899 — 30,193 — 30,193 
SDG&E:     
Long-term debt(4)
$8,950 $— $7,760 $— $7,760 
SoCalGas:     
Long-term debt(5)
$7,359 $— $6,880 $— $6,880 
(1)    Before allowances for credit losses of $4 and $5 at September 30, 2025 and December 31, 2024, respectively. Excludes unamortized transaction costs of $3 at both September 30, 2025 and December 31, 2024, respectively.
(2)    After the effects of interest rate swaps. Before reductions of unamortized discount and debt issuance costs of $121 at September 30, 2025.
(3)    After the effects of interest rate swaps at December 31, 2024. Before reductions of unamortized discount and debt issuance costs of $311 and $382 at September 30, 2025 and December 31, 2024, respectively, and excluding finance lease obligations of $1,305 and $1,315 at September 30, 2025 and December 31, 2024, respectively.
(4)    Before reductions of unamortized discount and debt issuance costs of $99 and $95 at September 30, 2025 and December 31, 2024, respectively, and excluding finance lease obligations of $1,181 and $1,205 at September 30, 2025 and December 31, 2024, respectively.
(5)    Before reductions of unamortized discount and debt issuance costs of $81 and $65 at September 30, 2025 and December 31, 2024, respectively, and excluding finance lease obligations of $124 and $110 at September 30, 2025 and December 31, 2024, respectively.
We provide the fair values for the securities held in the NDT related to SONGS in Note 12.
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NOTE 10. CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST
SEMPRA INFRASTRUCTURE
Investor Equity Subscription
In September 2025, PA2 JVCo issued 49.9% of its equity interests to Blackstone for $3.4 billion in cash at closing and a commitment to fund an additional $3.6 billion of capital contributions on a pre-determined funding schedule whereby Blackstone’s capital contributions are scheduled prior to SI Partners capital contributions. SI Partners holds the remaining 50.1% of equity interests in PA2 JVCo, and has committed to fund up to $7.8 billion to PA2 JVCo to support its share of the budgeted PA LNG Phase 2 project construction costs. SI Partners will continue to consolidate PA2 JVCo and direct the activities related to the construction and future operation and maintenance of the PA LNG Phase 2 project. Following the closing, Sempra, Blackstone, KKR Pinnacle and ADIA each hold a 35.1%, 49.9%, 10% and 5% ownership interest, respectively, in the PA LNG Phase 2 project.
Upon closing the equity subscription, we received proceeds of $106 million and recorded an increase of $76 million in CRNCI, an increase of $9 million in NCI, and an increase of $16 million, net of $5 million in income tax expense, in Sempra’s shareholders’ equity. Additionally at closing, Blackstone paid its initial contribution and we received $3,166 million in cash, net of $168 million in transaction costs, and recorded an increase of $3,166 million in CRNCI.
Distributions and Earnings Allocation
Distributions from PA2 JVCo will be made quarterly from available cash to the members in accordance with their distribution percentages, which initially allocates 40.1% and 59.9% of distributions to SI Partners and Blackstone, respectively, until December 31, 2070, after which distributions convert to 50.1% and 49.9% to SI Partners and Blackstone, respectively. Blackstone is entitled to certain adjustments to its share of distributions upon the occurrence of certain events, including termination of LNG offtake contracts that have not been replaced within a specified timeframe, extended incidents of operational underperformance, or material breach of certain affiliate contracts. In the event of liquidation, distributions will continue to follow this allocation until Blackstone has achieved a contractually specified return on its contributed capital, after which such proceeds from liquidation are distributed to SI Partners and Blackstone proportionate to their ownership interest.
Earnings are generally allocated 40.1% to SI Partners and 59.9% to Blackstone, subject to adjustments to Blackstone’s share of distributions discussed above.
Call Rights and Redemption Features
Under the PA2 JVCo LLCA, SI Partners has the right to appoint up to eight managers and Blackstone has the right to appoint up to two managers to PA2 JVCo’s board of managers, with voting power proportionate to their ownership interest. Blackstone has customary minority protections, including consent rights over significant actions such as amendments to the PA2 JVCo LLCA, incurrence of material indebtedness, and changes to the project budget.
Call Options. The PA2 JVCo LLCA provides SI Partners with several call rights to purchase Blackstone’s equity interest under certain conditions or upon the occurrence of certain contingent events, including if Blackstone fails to fund required capital contributions or becomes subject to specific disqualifying events, and during certain defined time periods. Blackstone has a reciprocal call right if SI Partners becomes subject to similar disqualifying events, generally at fair market value in a bankruptcy scenario or 75% of fair market value for other disqualifying events.
Contingent Redemption. Blackstone’s equity interest represents an NCI in PA2 JVCo and is classified as contingently redeemable because Blackstone has certain redemption and exit rights that are outside the control of SI Partners. These rights include, among others, the ability to require redemption upon (i) failure to complete construction by a specified date; (ii) sustained priority distributions to Blackstone above specified thresholds and for specified time periods as a result of extended periods of operational underperformance exceeding certain thresholds, termination of LNG offtake contracts that have not been replaced within a specified timeframe, or material breach of certain affiliate contracts; or (iii) the occurrence of certain monetization events, including a third-party sale of PA2 JVCo.
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Because these redemption features are contingent on events not solely within SI Partners’ control, we present Blackstone’s equity interest as a CRNCI, which appears between liabilities and equity in the mezzanine section of Sempra’s Condensed Consolidated Balance Sheet. We initially recorded the CRNCI at the amount for which Blackstone has a claim on the underlying net assets in liquidation at book value. At September 30, 2025, the CRNCI is not currently redeemable, nor is it probable that it will become redeemable because the forecasted completion of the PA LNG Phase 2 project is highly unlikely to occur beyond the contractually specified date in which Blackstone’s ownership interest becomes redeemable; therefore, we did not accrete the CRNCI to its redemption value. If it becomes probable that the CRNCI will become redeemable, we will make a policy election at that time regarding our accounting method of accreting the CRNCI to its redemption value.
Either party may propose a third-party sale or other monetization event. Proceeds from such a sale or monetization event are generally allocated 40.1% to SI Partners and 59.9% to Blackstone until Blackstone achieves a contractually specified return on its contributed capital, and thereafter 90% to SI Partners and 10% to Blackstone.
Allocation of Interests
Upon reaching FID in September 2025, Port Arthur LNG II paid $1.9 billion to Port Arthur LNG I for a 50% ownership interest in shared common facilities located at the site of the natural gas liquefaction projects. As a result, claim on the underlying common facilities in liquidation is split equally between the PA LNG Phase 1 project and the PA LNG Phase 2 project. However, although the ultimate cost of the common facilities will be split equally between the PA LNG Phase 1 project and the PA LNG Phase 2 project upon completion of the PA LNG Phase 2 project, payments for construction costs associated with the common facilities may be made by one project on behalf of both, necessitating an allocation of the appropriate claim on the underlying common facilities between the PA LNG Phase 1 project and the PA LNG Phase 2 project.
Because ownership interests in SI Partners, its subsidiaries and their projects differ by percentage and consolidation level, the allocation of claims on the underlying transactions must be further allocated among the respective owners. Such transactions also include the equity subscription, contributions provided by owners at different times based on a pre-determined funding schedule, and transaction costs, which include $122 million paid to Blackstone for fees and reimbursement of certain transaction expenses and $46 million paid to third parties. To effect the allocation of interests, in the three months and nine months ended September 30, 2025, we recorded a decrease in CRNCI of $1,309 million, an increase in NCI of $455 million and an increase in Sempra’s shareholders’ equity of $635 million, net of $219 million in income tax expense.
NOTE 11. SEMPRA – EQUITY AND EARNINGS PER COMMON SHARE
SERIES C PREFERRED STOCK
On September 10, 2025, we provided notice of the redemption of all 900,000 issued and outstanding shares of our series C preferred stock for a redemption price in cash of $1,000 per share. Because this notice made redemption unconditional and certain to occur, we reclassified $900 million from Preferred Stock in equity to Mandatorily Redeemable Preferred Stock in current liabilities on our Condensed Consolidated Balance Sheet, and the formerly outstanding 900,000 shares of series C preferred stock have been returned to the status of authorized and unissued shares. After this reclassification, we recognized $11 million of capitalized underwriting discount and equity issuance costs in Preferred Deemed Dividends and $4 million of accrued dividends through October 14, 2025 in Interest Expense on our Condensed Consolidated Statement of Operations.
On October 15, 2025, we effected and paid $900 million for the redemption of all 900,000 shares of our series C preferred stock using proceeds received from our August 2025 issuance of junior subordinated notes and short-term debt, which we discuss in Note 7.
COMMON STOCK OFFERINGS
ATM Program
In November 2024, we established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion through agents acting as our sales agents or as forward sellers or directly to the agents as principals. The shares may be offered and sold in amounts and at times to be determined by us from time to time. The agents will be entitled to a commission that will not exceed 1.0% of the gross sales price of all shares sold through it as agent pursuant to the Sales Agreement.
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Under the ATM program, we may enter into separate forward sale agreements with affiliates of the agents as forward purchasers. We expect to fully physically settle each forward sale agreement. However, we will generally have the right, subject to certain exceptions, to elect to cash settle or net share settle all or any portion of our obligations under any such forward sale agreement. With respect to forward sale agreements with any forward purchaser, we expect that such forward purchaser (or its affiliate) will attempt to borrow from third parties and sell, through the relevant agent acting as sales agent for such forward purchaser, shares of our common stock to hedge such forward purchaser’s exposure under such forward sale agreement. We will not receive any proceeds from any sale of shares borrowed by a forward purchaser (or its affiliate) and sold through a forward seller. The forward seller will receive a commission, in the form of a reduction to the initial forward price under the related forward sale agreement, at a mutually agreed rate that will not exceed (subject to certain exceptions) 1.0% of the volume-weighted average of the gross sales price per share of all of the borrowed shares of Sempra common stock sold through such forward seller.
We intend to use a substantial portion of the net proceeds we receive from the issuance and sale by us of any shares of our common stock to or through the agents and any net proceeds we receive through the settlement of any forward sale agreements with the forward purchasers for working capital and other general corporate purposes, including to partly finance our long-term capital plan and to repay outstanding commercial paper and potentially other indebtedness. At September 30, 2025, approximately $2.6 billion of common stock remained available for sale under the ATM program, which reflects the forward sale agreements that we describe below.
Forward Sale Agreements
Since establishing the ATM program, an aggregate of 4,996,591 shares have been sold under the forward sale agreements described below with an average initial forward price of $83.175. Such average initial forward price is weighted to take into account the number of shares sold under each forward sale agreement.
In the fourth quarter of 2024, we entered into a forward sale agreement under the ATM program with Bank of America, N.A. as forward purchaser. From time to time during the quarter at our instruction, the forward purchaser borrowed, and an affiliate of the forward purchaser sold, 2,909,274 shares of Sempra common stock under this agreement. At the initial forward price of $92.1546 per share, the proceeds from this forward sale agreement if we elect full physical settlement would be approximately $268 million (net of sales commissions of approximately $2.4 million, but before deducting equity issuance costs, and subject to certain adjustments pursuant to the forward sale agreements). At September 30, 2025, a total of 2,909,274 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than June 30, 2026.
In the first quarter of 2025, we entered into a forward sale agreement under the ATM program with Wells Fargo Bank, N.A. as forward purchaser. From time to time during the quarter at our instruction, the forward purchaser borrowed, and an affiliate of the forward purchaser sold, 2,087,317 shares of Sempra common stock under this agreement. At the initial forward price of $70.6593 per share, the proceeds from this forward sale agreement if we elect full physical settlement would be approximately $147 million (net of sales commissions of approximately $1.3 million, but before deducting equity issuance costs, and subject to certain adjustments pursuant to the forward sale agreements). At September 30, 2025, a total of 2,087,317 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than March 31, 2027.
The shares offered pursuant to the forward sale agreements were borrowed by the applicable forward purchaser and therefore were not newly issued shares. We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreements. Although we may settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements. The forward sale agreements are also subject to acceleration by the applicable forward purchaser upon the occurrence of certain events.
COMMON STOCK REPURCHASES
In the nine months ended September 30, 2025 and 2024, we withheld 684,447 shares for $58 million and 565,571 shares for $41 million, respectively, of our common stock that would otherwise be issued to long-term incentive plan participants who do not elect otherwise upon the vesting of RSUs and exercise of stock options in an amount sufficient to satisfy minimum statutory tax withholding requirements. Such share withholding is considered a share repurchase for accounting purposes.
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NONCONTROLLING INTERESTS
Ownership interests in a consolidated entity that are held by unconsolidated owners are accounted for and reported as NCI.
The following table summarizes net income attributable to Sempra and transfers (to) from NCI, which shows the effects of changes in Sempra’s ownership interest in its subsidiaries on Sempra’s shareholders’ equity.
NET INCOME ATTRIBUTABLE TO SEMPRA AND TRANSFERS (TO) FROM NCI
(Dollars in millions)
Three months endedNine months ended
 September 30, 2025
Sempra: 
Net income attributable to Sempra$95 $1,485 
Transfers (to) from NCI:
Increase in shareholders’ equity from investor equity subscription
16 16 
Increase in shareholders’ equity from allocation of interests(1)
635 635 
Net transfers (to) from NCI651 651 
Change from net income attributable to Sempra and transfers (to) from NCI$746 $2,136 
(1)    We describe the allocation of interests in Note 10.
SI Partners Subsidiaries
Both SI Partners and ConocoPhillips have provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. As of September 30, 2025, an aggregate amount of $2.7 billion has been paid by SI Partners’ subsidiary in satisfaction of its commitment to fund its portion of the development budget of the PA LNG Phase 1 project.
EARNINGS PER COMMON SHARE
Basic EPS is calculated by dividing earnings attributable to common shares 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.
EARNINGS PER COMMON SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra:
Numerator:    
Earnings attributable to common shares$77 $638 $1,444 $2,152 
Denominator:    
Weighted-average common shares outstanding for basic EPS(1)
652,948 633,752 652,538 633,342 
Dilutive effect of common shares sold forward267 2,312 123 1,375 
Dilutive effect of stock options and RSUs(2)
794 1,997 759 1,849 
Weighted-average common shares outstanding for diluted EPS654,009 638,061 653,420 636,566 
EPS:
Basic$0.12 $1.01 $2.21 $3.40 
Diluted$0.12 $1.00 $2.21 $3.38 
(1)    Includes 492 and 615 fully vested RSUs held in our Deferred Compensation Plan for the three months ended September 30, 2025 and 2024, respectively, and 502 and 616 of such RSUs for the nine months ended September 30, 2025 and 2024, respectively. 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 13 of the Notes to Consolidated Financial Statements in the Annual Report, dilutive RSUs may vary widely from period-to-period.
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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 the three months and nine months ended September 30, 2025 excludes 331,462 and 743,454 potentially dilutive shares, respectively, and the computation of diluted EPS for the three months and nine months ended September 30, 2024 excludes 450,243 and 996,966 potentially dilutive shares, respectively, because to include them would be antidilutive for the period. However, these shares could potentially dilute basic EPS in the future.
The potentially dilutive impact from the forward sale of our common stock pursuant to the forward sale agreements that we discuss above is reflected in our diluted EPS calculation using the treasury stock method. We anticipate there will be a dilutive effect on our EPS when the average market price of our common stock shares is above the applicable adjusted forward price, subject to increase or decrease based on the overnight bank funding rate, less a spread, and subject to decrease by amounts related to expected dividends on shares of our common stock during the term of the forward sale agreements. Additionally, if we decide to physically settle or net share settle the forward sale agreements, delivery of our shares to the forward purchasers on any such physical settlement or net share settlement of the forward sale agreements would result in dilution to our EPS.
Pursuant to Sempra’s share-based compensation plans, the Compensation and Talent Development Committee of Sempra’s board of directors granted 303,614 nonqualified stock options, 628,413 performance-based RSUs and 260,012 service-based RSUs in the nine months ended September 30, 2025, primarily in January.
We discuss share-based compensation plans and related awards and the terms and conditions of Sempra’s equity securities further in Notes 11, 12 and 13 of the Notes to Consolidated Financial Statements in the Annual Report.
NOTE 12. SAN ONOFRE NUCLEAR GENERATING STATION
We provide below updates to ongoing matters related to SONGS, a nuclear generating facility near San Clemente, California that permanently ceased operations in June 2013, and in which SDG&E has a 20% ownership interest. We discuss SONGS further in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
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 be completed around 2030. 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 an independent spent fuel storage installation and puts in place a program for the fuel’s disposal. SDG&E is responsible for approximately 20% of the total decommissioning cost.
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 Condensed 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 January 2025, the CPUC granted SDG&E authorization to access NDT funds of up to $66 million for forecasted 2025 costs.
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Nuclear Decommissioning Trusts
The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT on the Sempra and SDG&E Condensed Consolidated Balance Sheets. We provide additional fair value disclosures for the NDT in Note 9.
NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
 CostGross
unrealized
gains		Gross
unrealized
losses		Estimated
fair
value
September 30, 2025
Short-term investments, primarily cash equivalents$21 $— $— $21 
Equity securities69 225 (2)292 
Debt securities:    
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies(1)
53 1 — 54 
Municipal bonds(2)
299 3 (6)296 
Other securities(3)
252 5 (3)254 
Total debt securities604 9 (9)604 
Receivables (payables), net(20)— — (20)
Total$674 $234 $(11)$897 
December 31, 2024
Short-term investments, primarily cash equivalents$10 $— $— $10 
Equity securities78 223 (3)298 
Debt securities:    
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies67 1 (1)67 
Municipal bonds295 1 (9)287 
Other securities234 2 (8)228 
Total debt securities596 4 (18)582 
Receivables (payables), net(15)— — (15)
Total$669 $227 $(21)$875 
(1)    Maturity dates are 2025-2056.
(2)    Maturity dates are 2025-2065.
(3)    Maturity dates are 2025-2070.
The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales.
SALES OF SECURITIES IN THE NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Proceeds from sales$210 $259 $709 $639 
Gross realized gains12 17 43 41 
Gross realized losses1 2 6 7 
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 Condensed 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 is $448 million at September 30, 2025 and is based on a cost study prepared in 2024, which is pending CPUC approval. SDG&E expects to receive an FD in the first half of 2026.
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NOTE 13. COMMITMENTS, CONTINGENCIES AND GUARANTEES
LEGAL PROCEEDINGS
We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to reasonably estimate the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed, and in some cases have exceeded, applicable insurance coverage and could materially adversely affect our business, results of operations, financial condition, cash flows and/or prospects. Unless otherwise indicated, we are unable to reasonably estimate possible losses or a range of losses in excess of any amounts accrued.
At September 30, 2025, loss contingency accruals for legal matters that are probable and estimable are $43 million for Sempra, including $28 million for SoCalGas.
SDG&E
City of San Diego Franchise Agreements
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.
Pending. In one of the cases, the court ruled in favor of SDG&E and the City of San Diego, upholding all terms of the franchise agreements, except for the two-thirds City Council vote requirement for termination if the City decides to terminate under certain circumstances. Under the court’s ruling, the City can instead terminate on a majority vote, so long as it satisfies repayment provisions under the franchise agreements. Both sides have appealed the ruling.
Resolved. In the second case, judgment was granted in favor of SDG&E and the City of San Diego. The plaintiff’s latest appeal was to the California Supreme Court and was denied, definitively resolving this matter.
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.
In 2022, SoCalGas paid $1.79 billion under a settlement agreement that resolved the lawsuits of over 99% of the approximately 36,000 individual plaintiffs with lawsuits then-pending against SoCalGas and Sempra related to the Leak. As of October 31, 2025, there are three outstanding plaintiffs who have not agreed to a settlement in principle.
Other Sempra
Energía Costa Azul
We describe below certain land 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 conclusions 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.
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Land Disputes.
▪Pending - Sempra Infrastructure has been engaged in a long-running land dispute with a claimant 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). The claimant to the adjacent property filed suit to reinitiate an administrative procedure at SEDATU to obtain the property title for the disputed property that had previously been issued in a ruling by the federal Agrarian Court and subsequently reversed by a federal court in Mexico. In April 2021, the proceeding in the Agrarian Court concluded with the court ordering that the administrative procedure be restarted. The administrative procedure at SEDATU may continue if SEDATU decides to reopen the matter.
▪Resolved - In addition, a plaintiff filed a claim in the federal Agrarian Court that 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. In August 2024, the Federal Collegiate Circuit Court ruled in favor of the ECA Regas Facility. The plaintiff filed an appeal and, in May 2025, the Mexican Supreme Court dismissed the appeal, definitively resolving this matter.
Environmental and Social Impact Permits. Several administrative challenges are pending before Mexico’s Secretariat of Environment and Natural Resources (the Mexican environmental protection agency) and Federal Tax and Administrative Courts, seeking revocation of the environmental impact authorization issued to the ECA Regas Facility in 2003. These cases generally allege that the conditions and mitigation measures in the environmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines.
In 2018 and 2021, three related claimants filed separate challenges in the federal district court in Ensenada, Baja California seeking revocation of 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:
▪Pending - In the first case, the court issued a provisional injunction against the permits 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 to cancel the injunction to the federal appellate court but was not successful. The lower court’s ruling was favorable to the ECA Regas Facility, as the court determined that no harm has been caused to the plaintiff and dismissed the lawsuit. The claimant appealed and petitioned the Mexican Supreme Court to resolve the appeal. The Mexican Supreme Court denied the petition to hear the case, thereby leaving the appeal to be resolved by a federal appellate court.
▪Pending - In the second case, the initial request for a provisional injunction against the permits 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 construction activities did not violate the injunction. The claimants appealed this ruling to the federal appellate court but were not successful. The lower court’s ruling was favorable to the ECA Regas Facility, as the court determined that no harm has been caused to the plaintiffs and dismissed the lawsuit. The claimants appealed and petitioned the Mexican Supreme Court to resolve the appeal. The Mexican Supreme Court denied the petition to hear the case, thereby leaving the appeal to be resolved by a federal appellate court.
▪Pending - In the third case, a group of residents filed an administrative appeal 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 administrative appeal was denied. The claimants appealed this ruling via a constitutional challenge (an amparo trial) but were not successful. The lower court’s ruling was favorable to the ECA Regas Facility, as the court determined that no harm has been caused to the plaintiffs and dismissed the lawsuit. The claimants appealed the rulings via the Second Federal Collegiate Court, and the appeal is yet to be resolved.
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Port Arthur LNG I
TCEQ Permit - Pending. The PA LNG Phase 1 project holds two Clean Air Act, Prevention of Significant Deterioration permits issued by the TCEQ, which we refer to as the “2016 Permit” and the “2022 Permit.” The 2022 Permit also governs emissions for the PA LNG Phase 2 project. In November 2023, a panel of the U.S. Court of Appeals for the Fifth Circuit issued a decision to vacate and remand the 2022 Permit to the TCEQ for additional explanation of the agency’s permit decision. In February 2024, the court withdrew its opinion and referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. In February 2025, the Supreme Court of Texas adopted Port Arthur LNG I’s interpretation of the standard. In August 2025, the U.S. Court of Appeals for the Fifth Circuit applied the standard adopted by the Supreme Court of Texas and denied the petitioner’s argument under the case, resulting in the continued effectiveness of the 2022 Permit. The petitioners have until November 10, 2025 to file a petition for writ of certiorari with the U.S. Supreme Court; however, the Supreme Court does not have to grant review. The 2022 Permit is effective during the pending litigation. The 2016 Permit was not the subject of, and is unaffected by, the pending litigation of the 2022 Permit. Construction of the PA LNG Phase 1 project is proceeding uninterrupted under existing permits, and we do not currently anticipate the pending litigation to materially impact the PA LNG Phase 1 project cost, schedule or expected commercial operations at this stage.
Construction Incident - Pending. In April 2025, an incident occurred at the site of the PA LNG Phase 1 project that resulted in the deaths of three Bechtel employees and injuries to two Bechtel employees.
We have an EPC contract with Bechtel to construct the PA LNG Phase 1 project. Under the EPC contract, Bechtel has full custody and control of the site during the construction period. OSHA opened inspections with respect to Bechtel and Sempra Infrastructure, but has released the site. Bechtel is continuing construction of the PA LNG Phase 1 project while the cause of the incident remains under investigation.
As of October 31, 2025, there are two pending lawsuits filed by 17 plaintiffs in the 172nd Judicial District Court in Jefferson County, Texas and the 295th Judicial District Court in Harris County, Texas. A complaint filed in the 60th Judicial District Court in Jefferson County, Texas was dismissed without prejudice following the plaintiff’s intervention in the proceeding in the 172nd Judicial District Court in Jefferson County, Texas. The complaints collectively name as defendants Port Arthur LNG I, SI Partners, Sempra and/or other Sempra affiliates, Bechtel and/or Bechtel Corporation, and ConocoPhillips. In the lawsuits, plaintiffs assert negligence and gross negligence and additional causes of action for wrongful death, survival and bystander claims. Plaintiffs seek compensatory and punitive damages, lost wages and attorneys’ fees. The litigation is stayed pending a request to transfer the pending cases to a multidistrict litigation pretrial court.
Bechtel is providing indemnity pursuant to the terms of Port Arthur LNG I’s EPC contract.
Litigation Related to Regulatory and Other Actions by the Mexican Government
Amendments to Mexico’s Electricity Industry Law. In March 2021, the Mexican government published a decree with amendments to the LIE that included public policy changes, including establishing priority of dispatch for CFE plants over privately owned ones and allowing the CNE to revoke self-supply permits granted under the former electricity law under certain circumstances. In 2024, the Mexican government adopted changes to the Mexican Constitution to reinforce state control over strategic sectors by granting a central role to government entities like the CFE and PEMEX. Following these constitutional reforms, the Mexican government adopted the ESL in March 2025, which repealed the LIE.
Prior to the enactment of the ESL, Sempra Infrastructure had initiated three amparo lawsuits challenging the 2021 amendments to the LIE. The first lawsuit addressed the provision allowing revocation of self-supply permits, which lawsuit the Second Collegiate Court definitively dismissed in July 2024. The second lawsuit impacted generation permits for certain Sempra Infrastructure facilities, which lawsuit the Second Chamber of the Mexican Supreme Court definitively dismissed in February 2025. The third lawsuit relating to the 2021 amendments to the LIE impacts Sempra Infrastructure’s power marketing business; this lawsuit remains pending, but Sempra Infrastructure believes it is now moot given the repeal of the LIE.
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.
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LEASES
We discuss leases further in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
Lessee Accounting
We have operating and finance leases for real and personal property (including office space, land, fleet vehicles, aircraft, tugboats, machinery and equipment, warehouses and other operational facilities) and PPAs with renewable energy, energy storage and peaker plant facilities.
SDG&E has two PPAs that commenced in July 2025 and September 2025 and expire in June 2040 and August 2040, respectively, and recorded right-of-use assets and operating lease liabilities of $291 million. Future minimum lease payments are $12 million in 2025, and $29 million in each of 2026 through 2029 and $303 million thereafter.
Leases That Have Not Yet Commenced
SDG&E previously entered into two PPAs, of which SDG&E expects one will commence in 2027 and one will commence in 2028. SDG&E expects the future minimum lease payments to be $4 million in 2028, $5 million in 2029 and $71 million thereafter (through expiration in 2043).
SoCalGas previously entered into a lease agreement for a new headquarters office space in Los Angeles that it expects will commence in 2026. In July 2025, the lease agreement was amended to increase the square footage. At September 30, 2025, SoCalGas expects future minimum lease payments to decrease by $3 million in 2028 and increase by $3 million in 2029 and $38 million thereafter (through expiration in 2041) compared to December 31, 2024.
Lessor Accounting
Sempra Infrastructure is a lessor for certain of its natural gas and ethane pipelines, compressor stations, liquid petroleum gas storage facilities, a rail facility and refined products terminals, which we account for as operating or sales-type leases.
We provide information below for leases for which we are the lessor.
LESSOR INFORMATION ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
Three months ended September 30,Nine months ended September 30,
2025202420252024
Sempra – Sales-type leases:
Interest income$— $1 $2 $4 
Total revenues from sales-type leases(1)
$— $1 $2 $4 
Sempra – Operating leases:
Fixed lease payments$93 $83 $269 $259 
Variable lease payments6 9 17 29 
Total revenues from operating leases(1)
$99 $92 $286 $288 
Depreciation expense$18 $17 $53 $53 
(1)    Included in Revenues: Energy-Related Businesses on the Condensed Consolidated Statements of Operations.

CONTRACTUAL COMMITMENTS
We discuss below significant changes in the first nine months of 2025 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
Natural Gas Contract
Sempra Infrastructure
Sempra Infrastructure entered into a 20-year transportation services agreement to secure natural gas transportation capacity, with an option to extend the term, resulting in a commitment for fixed costs of approximately $180 million per year during the term of the agreement.
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LNG Purchase Agreement
ECA Regas Facility
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 2025 through 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. At September 30, 2025, we expect the commitment amount to decrease by $321 million in 2025, $74 million in 2026, $53 million in 2027, $64 million in 2028, and $38 million in 2029 compared to December 31, 2024, reflecting changes in estimated forward prices since December 31, 2024 and actual transactions for the first nine months of 2025. These LNG commitment amounts are based on the assumption that all LNG cargoes under the agreement are delivered, less those already confirmed to be diverted as of September 30, 2025. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amount provided under the agreement due to the supplier electing to divert cargoes as allowed by the agreement.
ENVIRONMENTAL ISSUES
We disclose any proceeding under environmental laws to which a government authority is a party when the potential monetary sanctions, exclusive of interest and costs, exceed the lesser of $1 million or 1% of current assets, which is $317 million for Sempra, $17 million for SDG&E and $15 million for SoCalGas at September 30, 2025.
SEMPRA – GUARANTEES
Sempra Promissory Note for SDSRA Distribution
Cameron LNG JV’s debt agreements require Cameron LNG JV to maintain the SDSRA, which is an additional reserve account beyond the Senior Debt Service Accrual Account, where funds accumulate from operations to satisfy senior debt obligations due and payable on the next payment date. Both accounts can be funded with cash or authorized investments. In June 2021, Sempra Infrastructure received a distribution of $165 million based on its proportionate share of the SDSRA, for which Sempra provided a promissory note and letters of credit to secure a proportionate share of Cameron LNG JV’s obligation to fund the SDSRA. Sempra’s maximum exposure to loss is replenishment of the amount withdrawn by Sempra Infrastructure from the SDSRA, or $165 million. We recorded a guarantee liability of $22 million in June 2021, with an associated carrying value of $17 million at September 30, 2025, 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.
This guarantee will remain with Sempra after the sale of a portion of our equity interest in SI Partners is complete, which we discuss in Note 6.
Sempra Support Agreement for CFIN
In July 2020, CFIN entered into a financing arrangement with Cameron LNG JV’s four project owners and received aggregate proceeds of $1.5 billion from two project owners and from external lenders on behalf of the other two project owners (collectively, the affiliate loans), based on their proportionate ownership interest in Cameron LNG JV. CFIN used the proceeds from the affiliate loans to provide a loan to Cameron LNG JV. The affiliate loans mature in 2039. Principal and interest are 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 Infrastructure’s $753 million proportionate share of the affiliate loans, based on SI Partners’ 50.2% ownership interest in Cameron LNG JV, was funded by external lenders comprised of a syndicate of 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;
▪on March 28, 2028, March 28, 2030 and March 28, 2035, the agent for the external lenders, on behalf of such external lenders, is obligated to put all of the then outstanding bank debt to Sempra Infrastructure, except to the extent any external lender elects not to participate in the put three months prior to the applicable put exercise date;
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▪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 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 recognizes as interest income as earned. Sempra’s maximum exposure to loss is the bank debt plus any accrued and unpaid interest and related fees, subject to a liability cap of 130% of the bank debt, or $979 million. We measure the Support Agreement at fair value, net of related guarantee fees, on a recurring basis (see Note 9). At September 30, 2025, the fair value of the Support Agreement is $39 million, of which $8 million is included in Other Current Assets and $31 million is included in Other Long-Term Assets on Sempra’s Condensed Consolidated Balance Sheet.
This guarantee will remain with Sempra after the sale of a portion of our equity interest in SI Partners is complete, which we discuss in Note 6.
SI Partners Credit Support Agreement
In February 2025, SI Partners entered into a 15-month credit support agreement with a third-party financial institution related to a customer’s secured borrowing for repayment of its past due account balance owed to SI Partners. At September 30, 2025, SI Partners’ maximum exposure to loss under this off-balance sheet arrangement is $72 million.
This guarantee, if not yet terminated, will remain with SI Partners after the sale of a portion of our equity interest in SI Partners is complete, which we discuss in Note 6.
NOTE 14. SEGMENT INFORMATION
SEMPRA
Sempra is a California-based holding company whose businesses invest in, develop and operate energy infrastructure in North America and provide electric and gas services to customers. Sempra has the following three operating and reportable segments, which are managed separately based on services provided, geographic location and regulatory framework:
▪Sempra California provides natural gas and electric service to Southern California and part of central California through Sempra’s wholly owned subsidiaries, SDG&E and SoCalGas, which are regulated public utilities.
▪Sempra Texas Utilities holds our equity method investment in Oncor Holdings, which owns an 80.25% interest in Oncor, a regulated electric transmission and distribution utility serving customers in the north-central, eastern, western and panhandle regions of Texas; and our equity method investment in Sharyland Holdings, L.P., which owns Sharyland Utilities, a regulated electric transmission utility serving customers near the Texas-Mexico border.
▪Sempra Infrastructure includes the operating companies of SI Partners, in which Sempra Infrastructure owns a 70% interest, as well as a holding company and certain services companies. Sempra Infrastructure develops, builds, operates and invests in energy infrastructure to help provide safe, sustainable and reliable access to cleaner energy in markets in the U.S., Mexico and globally.
Sempra’s CODM is its chief executive officer, who uses segment earnings attributable to common shares predominantly in the annual financial planning process to assess financial performance. Sempra’s CODM prioritizes resource allocation to each segment in a manner that aligns with Sempra’s capital expenditures plan.
Amounts labeled as “Parent and other,” which does not meet the definition of an operating or reportable segment, consist primarily of activities of parent organizations.
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The following tables present selected information by segment and reconciliations of assets, capital expenditures for PP&E, and earnings attributable to common shares to Sempra’s consolidated totals.
SEGMENT INFORMATION
(Dollars in millions)
September 30,
2025		December 31,
2024
ASSETS
Sempra California$59,479 $56,116 
Sempra Texas Utilities17,173 15,534 
Sempra Infrastructure30,140 22,954 
Segment totals106,792 94,604 
Parent and other
1,162 2,622 
Intersegment eliminations(1)
(1,035)(1,071)
Total Sempra$106,919 $96,155 
EQUITY METHOD INVESTMENTS
Sempra Texas Utilities$17,164 $15,522 
Sempra Infrastructure(2)
17 2,411 
Segment totals/Total Sempra$17,181 $17,933 
Three months ended September 30,Nine months ended September 30,
2025202420252024
EQUITY EARNINGS
Equity earnings, before income tax:
Sempra Texas Utilities$1 $2 $4 $6 
Sempra Infrastructure132 130 439 420 
Segment totals133 132 443 426 
Equity earnings, net of income tax:
Sempra Texas Utilities306 261 661 646 
Sempra Infrastructure33 61 86 163 
Segment totals339 322 747 809 
Total Sempra$472 $454 $1,190 $1,235 
CAPITAL EXPENDITURES FOR PROPERTY, PLANT AND EQUIPMENT
Sempra California$3,334 $3,329 
Sempra Infrastructure3,863 2,433 
Segment totals7,197 5,762 
Parent and other4 3 
Total Sempra$7,201 $5,765 
(1)     Primarily includes an intersegment loan related to deferred income taxes from Sempra Infrastructure to Parent and other.
(2)     At September 30, 2025, $2,471 is classified as Assets Held for Sale on the Sempra Condensed Consolidated Balance Sheet. The remaining $17 represents our investment balance in Cameron LNG JV related to our guarantee under the SDSRA, which we discuss in Note 13.
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SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
Sempra California
Sempra Texas Utilities(1)
Sempra InfrastructureSempra
Three months ended September 30, 2025
Revenues
$2,613 $555 
Depreciation and amortization(591)(69)
Interest income
2 10 
Interest expense(2)
(234)(16)
Income tax benefit (expense)128 (792)
Equity earnings$307 165 
Earnings attributable to noncontrolling interests(55)
Other segment items(3)
(1,548)(1)(378)
Segment earnings attributable to common shares$370 $306 $(580)$96 
Parent and other(19)
Earnings attributable to common shares$77 
Three months ended September 30, 2024
Revenues
$2,256 $538 
Depreciation and amortization(536)(76)
Interest income
4 7 
Interest expense
(213)— 
Income tax benefit37 43 
Equity earnings$263 191 
Earnings attributable to noncontrolling interests(110)
Other segment items(3)
(1,301)(2)(363)
Segment earnings attributable to common shares$247 $261 $230 $738 
Parent and other(100)
Earnings attributable to common shares$638 
(1)    Substantially all earnings attributable to common shares are from equity earnings.
(2)    Sempra Infrastructure includes net unrealized gains (losses) from undesignated interest rate swaps related to the PA LNG Phase 1 project.
(3)    Includes cost of natural gas, cost of electric fuel and purchased power, O&M, franchise fees and other taxes, and other income (expense), net, for Sempra California; O&M, interest expense, and income tax expense for Sempra Texas Utilities related to activities at the holding company; and cost of natural gas, energy-related businesses cost of sales, O&M, franchise fees and other taxes, and other income (expense), net, for Sempra Infrastructure.
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SEGMENT INFORMATION (CONTINUED)
(Dollars in millions)
Sempra California
Sempra Texas Utilities(1)
Sempra InfrastructureSempra
Nine months ended September 30, 2025
Revenues
$8,504 $1,511 
Depreciation and amortization(1,727)(223)
Interest income
7 34 
Interest expense(2)
(687)(87)
Income tax benefit (expense)63 (1,045)
Equity earnings$665 525 
Earnings attributable to noncontrolling interests(103)
Other segment items(3)
(4,807)(5)(974)
Segment earnings attributable to common shares$1,353 $660 $(362)$1,651 
Parent and other(207)
Earnings attributable to common shares$1,444 
Nine months ended September 30, 2024
Revenues
$8,022 $1,466 
Depreciation and amortization(1,585)(221)
Interest income
12 19 
Interest expense
(627)— 
Income tax (expense) benefit(90)67 
Equity earnings$652 583 
Earnings attributable to noncontrolling interests(325)
Other segment items(3)
(4,587)(6)(937)
Segment earnings attributable to common shares$1,145 $646 $652 $2,443 
Parent and other(291)
Earnings attributable to common shares$2,152 
(1)    Substantially all earnings attributable to common shares are from equity earnings.
(2)    Sempra Infrastructure includes net unrealized gains (losses) from undesignated interest rate swaps related to the PA LNG Phase 1 project.
(3)    Includes cost of natural gas, cost of electric fuel and purchased power, O&M, franchise fees and other taxes, other income (expense), net, and preferred dividends for Sempra California; O&M, interest expense, and income tax expense for Sempra Texas Utilities related to activities at the holding company; and cost of natural gas, energy-related businesses cost of sales, O&M, franchise fees and other taxes, and other income (expense), net, for Sempra Infrastructure.
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The following table presents revenues by services by segment, reconciled to Sempra’s consolidated revenues.
REVENUES BY SERVICES
(Dollars in millions)
Sempra CaliforniaSempra InfrastructureSempraSempra CaliforniaSempra Infrastructure Sempra
Three months ended September 30, 2025Three months ended September 30, 2024
Revenues from external customers:
Utilities$2,513 $15 $2,388 $15 
Energy-related businesses— 228 — 167 
Total revenues from external customers(1)
2,513 243 $2,756 2,388 182 $2,570 
Other revenues(2):
Utilities95 — (138)— 
Energy-related businesses— 300 — 345 
Total other revenues95 300 395 (138)345 207 
Intersegment revenues(3):
Utilities5 — 6 — 
Energy-related businesses— 12 — 11 
Total intersegment revenues5 12 17 6 11 17 
Segment revenues$2,613 $555 3,168 $2,256 $538 2,794 
Adjustments— (1)
Intersegment eliminations(17)(17)
Revenues$3,151 $2,776 
Nine months ended September 30, 2025Nine months ended September 30, 2024
Revenues from external customers:
Utilities$8,412 $59 $8,113 $63 
Energy-related businesses— 666 — 575 
Total revenues from external customers(1)
8,412 725 $9,137 8,113 638 $8,751 
Other revenues(2):
Utilities74 — (107)— 
Energy-related businesses— 742 — 784 
Total other revenues74 742 816 (107)784 677 
Intersegment revenues(3):
Utilities18 — 16 — 
Energy-related businesses— 44 — 44 
Total intersegment revenues18 44 62 16 44 60 
Segment revenues$8,504 $1,511 10,015 $8,022 $1,466 9,488 
Adjustments— (1)
Intersegment eliminations(62)(60)
Revenues$9,953 $9,427 
(1)    We did not have revenues from transactions with a single external customer that amounted to 10% or more of Sempra’s total revenues.
(2)    See “Revenues from Sources Other Than Contracts with Customers” in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report for a description of this revenue source, which may be additive or subtractive from period to period.
(3)    See “Transactions with Affiliates” in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report for a description of services provided by one operating segment to another operating segment within Sempra.
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SDG&E
SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County. SDG&E has one operating and reportable segment.
In connection with certain organizational changes, effective July 5, 2025, SDG&E’s president assumed the responsibilities of the CODM. The CODM utilizes earnings attributable to common shares to manage the business, assess performance and allocate resources. SDG&E’s CODM was previously its chief executive officer.
Total assets at SDG&E were $32.8 billion and $30.8 billion at September 30, 2025 and December 31, 2024, respectively. The following table presents selected information for SDG&E’s single segment and reconciliation of earnings attributable to common shares.
SEGMENT INFORMATION
(Dollars in millions)
Three months ended September 30,Nine months ended September 30,
2025202420252024
SDG&E:
Revenues from external customers:
Electric$1,131 $1,160 $3,062 $3,178 
Natural gas218 167 789 658 
Total revenues from external customers(1)
1,349 1,327 3,851 3,836 
Regulatory revenues(2):
Electric132 (87)300 104 
Natural gas(1)3 11 37 
Total regulatory revenues131 (84)311 141 
Total revenues1,480 1,243 4,162 3,977 
Depreciation and amortization(334)(308)(977)(910)
Interest income— 1 2 5 
Interest expense(141)(131)(415)(390)
Income tax benefit (expense)33 (15)12 (89)
Other segment items(3)
(714)(529)(2,004)(1,923)
Earnings attributable to common shares$324 $261 $780 $670 
Capital expenditures for property, plant and equipment$1,811 $1,838 
(1)    SDG&E did not have revenues from transactions with a single external customer that amounted to 10% or more of its total revenues.
(2)    See “Revenues from Sources Other Than Contracts with Customers” in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report for a description of this revenue source, which may be additive or subtractive from period to period.
(3)    Includes cost of electric fuel and purchased power, cost of natural gas, O&M, franchise fees and other taxes, and other income (expense), net.
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SOCALGAS
SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California. SoCalGas has one operating and reportable segment.
SoCalGas’ CODM is its chief executive officer, who utilizes earnings attributable to common shares to manage the business, assess performance and allocate resources.
Total assets at SoCalGas were $26.7 billion and $25.4 billion at September 30, 2025 and December 31, 2024, respectively. The following table presents selected information for SoCalGas’ single segment and reconciliation of earnings attributable to common shares.
SEGMENT INFORMATION
(Dollars in millions)
Three months ended September 30,Nine months ended September 30,
2025202420252024
SoCalGas:
Natural gas:
Revenues from external customers(1)
$1,217 $1,110 $4,706 $4,416 
Regulatory revenues(2)
(36)(56)(237)(248)
Total revenues1,181 1,054 4,469 4,168 
Depreciation and amortization(257)(228)(750)(675)
Interest income2 3 5 7 
Interest expense(93)(82)(272)(237)
Income tax benefit (expense)95 52 51 (1)
Other segment items(3)
(882)(813)(2,930)(2,787)
Earnings (losses) attributable to common shares$46 $(14)$573 $475 
Capital expenditures for property, plant and equipment$1,523 $1,491 
(1)    SoCalGas did not have revenues from transactions with a single external customer that amounted to 10% or more of its total revenues.
(2)    See “Revenues from Sources Other Than Contracts with Customers” in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report for a description of this revenue source, which may be additive or subtractive from period to period.
(3)    Includes cost of natural gas, O&M, franchise fees and other taxes, other income (expense), net, and preferred dividends.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Page
Overview
96
Results of Operations by Registrant
97
Sempra
97
SDG&E
110
SoCalGas
113
Capital Resources and Liquidity
117
Critical Accounting Estimates
134
New Accounting Standards
134
OVERVIEW
This combined MD&A includes the operational and financial results of the following three Registrants:
▪Sempra is 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.
▪SDG&E is a regulated public utility that provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
▪SoCalGas is a regulated public natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
This combined MD&A should be read in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto in this report, and the Consolidated Financial Statements and the Notes thereto, “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A” in the Annual Report.
Sempra has the following three reportable segments, which reflect how the CODM oversees operational and financial performance:
▪Sempra California
▪Sempra Texas Utilities
▪Sempra Infrastructure
SDG&E and SoCalGas each has one reportable segment.
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RESULTS OF OPERATIONS BY REGISTRANT
Throughout this MD&A, our references to earnings represent earnings attributable to common shares. Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates unless otherwise noted) and after NCI but before foreign currency and inflation effects, where applicable.
Sempra logo.jpg
We discuss herein Sempra’s results of operations and significant changes in earnings, revenues and costs by segment, as well as Parent and other, for the three months (Q3) and nine months (YTD) ended September 30, 2025 compared to the same periods in 2024. We also discuss herein the impact of foreign currency and inflation rates on Sempra’s results of operations.
Due to the delay in the issuance of the CPUC’s FD in the SDG&E and SoCalGas 2024 GRC, Sempra California recorded revenues in the first three quarters of 2024 based on levels authorized for 2023 under the 2019 GRC. In December 2024, the CPUC approved an FD in the 2024 GRC, effective retroactive to January 1, 2024, for which Sempra California recorded the retroactive impacts in the fourth quarter of 2024. Sempra California’s authorized base revenues in the first three quarters of 2025 are based on the revenues authorized for the 2024 test year plus the amount authorized for attrition for 2025. We provide additional information on the 2024 GRC FD in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
(Dollars and shares in millions, except per share amounts)
282930

EARNINGS (LOSSES) BY SEGMENT 
(Dollars in millions) 
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra:
Sempra California
$370 $247 $1,353 $1,145 
Sempra Texas Utilities306 261 660 646 
Sempra Infrastructure
(580)230 (362)652 
Segment earnings attributable to common shares96 738 1,651 2,443 
Parent and other
(19)(100)(207)(291)
Earnings attributable to common shares
$77 $638 $1,444 $2,152 

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Sempra California
Sempra California’s earnings are comprised of SDG&E and SoCalGas. Because changes in SDG&E’s and SoCalGas’ 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 below. 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 Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
In the three months ended September 30, 2025 compared to the same period in 2024, the increase in earnings of $123 million (50%) was primarily due to:
▪$92 million higher income tax benefits primarily from flow-through items, including impacts from the election to accelerate self-developed software deductions, and from the resolution of prior year income tax items
▪$47 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $9 million lower authorized cost of capital. In the first three quarters of 2024, Sempra California recorded CPUC-authorized base revenues based on 2023 authorized levels
Offset by:
▪$16 million higher net interest expense
In the nine months ended September 30, 2025 compared to the same period in 2024, the increase in earnings of $208 million (18%) was primarily due to:
▪$134 million higher income tax benefits primarily from flow-through items, including gas repairs tax benefits (which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD) and impacts from the election to accelerate self-developed software deductions, and from the resolution of prior year income tax items
▪$119 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $31 million lower authorized cost of capital. In the first three quarters of 2024, Sempra California recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$10 million regulatory award approved by the CPUC in 2025
▪$7 million higher net regulatory interest income
▪$7 million higher electric transmission margin
Offset by:
▪$48 million higher net interest expense
▪$25 million from disallowed regulatory recovery of COVID-19 costs
Sempra Texas Utilities
In the three months ended September 30, 2025 compared to the same period in 2024, the increase in earnings of $45 million (17%) was primarily due to higher equity earnings from Oncor Holdings driven by:
▪overall higher revenues primarily attributable to:
◦rate updates to reflect increases in invested capital
◦increase due to Oncor’s SRP and the UTM
Offset by:
▪higher interest expense and depreciation expense associated with increases in invested capital
▪higher O&M
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In the nine months ended September 30, 2025 compared to the same period in 2024, the increase in earnings of $14 million (2%) was primarily due to higher equity earnings from Oncor Holdings driven by:
▪overall higher revenues primarily attributable to:
◦rate updates to reflect increases in invested capital
◦increase due to Oncor’s SRP and the establishment of the UTM
◦customer growth
Offset by:
▪higher interest expense and depreciation expense associated with increases in invested capital
▪higher O&M
Sempra Infrastructure
In the three months ended September 30, 2025 compared to the same period in 2024, losses were $580 million compared to earnings of $230 million primarily due to:
▪$705 million income tax expense in 2025 to adjust deferred income tax liabilities related to outside basis differences in our investment in SI Partners as a result of management’s decision to classify the asset as held for sale
▪$100 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $32 million unfavorable impact in 2025 compared to a $68 million favorable impact in 2024
▪$26 million unfavorable impact related to a customer’s early termination of firm transportation agreements, including interest expense
▪$18 million lower income tax benefit primarily from outside basis differences
▪$10 million higher O&M in 2025 from higher provisions for expected credit losses
Offset by:
▪$26 million from asset and supply optimization driven by higher optimization of transport and storage contracts offset by unrealized losses on commodity derivatives in 2025 compared to unrealized gains on commodity derivatives in 2024 due to changes in natural gas prices
▪$9 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement
In the nine months ended September 30, 2025 compared to the same period in 2024, losses were $362 million compared to earnings of $652 million primarily due to:
▪$731 million income tax expense in 2025 as a result of management’s decision to classify SI Partners and Ecogas as held for sale, comprised of the following:
◦$705 million income tax expense to adjust deferred income tax liabilities related to outside basis differences in our investment in SI Partners
◦$26 million income tax expense due to the recognition of a deferred tax liability on our outside basis difference in Ecogas
▪$302 million unfavorable impact from foreign currency and inflation effects on our monetary positions in Mexico, comprised of a $122 million unfavorable impact in 2025 compared to a $180 million favorable impact in 2024
▪$26 million unfavorable impact related to a customer’s early termination of firm transportation agreements, including interest expense
▪$17 million from TdM driven by lower volumes and lower power prices and unrealized losses in 2025 compared to unrealized gains in 2024 on commodity derivatives due to changes in power prices
▪$16 million lower income tax benefit primarily from outside basis differences
▪$9 million interest expense from unrealized losses in 2025 on interest rate swaps related to the PA LNG Phase 1 project
Offset by:
▪$26 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement
▪$22 million from asset and supply optimization driven by higher optimization of transport and storage contracts and higher LNG diversion fees offset by higher unrealized losses on commodity derivatives due to changes in natural gas prices
▪$12 million higher net interest income from a change in the fair value of the Support Agreement and higher capitalization of interest expense in 2025 from projects under construction
▪$7 million higher revenues due to the commencement of commercial operations at the Topolobampo marine terminal in June 2024
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Parent and Other
In the three months ended September 30, 2025 compared to the same period in 2024, the decrease in losses of $81 million was primarily due to:
▪$191 million net income tax benefit in 2025 from changes to a valuation allowance against certain tax credit carryforwards offset by changes in state income tax apportionment as a result of management’s decision to classify SI Partners as held for sale
▪$22 million income tax benefit in 2025 from the impacts of the OBBBA
▪$17 million income tax expense in 2024 from changes to a valuation allowance against certain tax credit carryforwards
Offset by:
▪$78 million income tax expense in 2025 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA
▪$30 million higher net interest expense
▪$13 million higher income tax expense from the interim period application of an annual forecasted consolidated ETR
▪$11 million preferred deemed dividends related to the notice of redemption of series C preferred stock in September 2025
▪$10 million lower net investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan
In the nine months ended September 30, 2025 compared to the same period in 2024, the decrease in losses of $84 million (29%) was primarily due to:
▪$191 million net income tax benefit in 2025 from changes to a valuation allowance against certain tax credit carryforwards offset by changes in state income tax apportionment as a result of management’s decision to classify SI Partners as held for sale
▪$22 million income tax benefit in 2025 from the impacts of the OBBBA
▪$17 million income tax expense in 2024 from changes to a valuation allowance against certain tax credit carryforwards
Offset by:
▪$78 million income tax expense in 2025 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA
▪$70 million higher net interest expense
▪$11 million preferred deemed dividends related to the notice of redemption of series C preferred stock in September 2025
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SIGNIFICANT CHANGES IN REVENUES AND COSTS
The regulatory framework permits SDG&E and SoCalGas to recover certain program expenditures and other costs authorized by the CPUC (referred to as “refundable programs”).
Utilities: Natural Gas Revenues and Cost of Natural Gas
Our utilities revenues include natural gas revenues at Sempra California and Sempra Infrastructure, which includes Ecogas. Intercompany revenues are eliminated in Sempra’s Condensed Consolidated Statements of Operations.
SDG&E and SoCalGas operate under a regulatory framework that permits the cost of natural gas purchased for core 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 SoCalGas and its core customers. We provide further discussion in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.
UTILITIES: NATURAL GAS REVENUES AND COST OF NATURAL GAS
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra:
Natural gas revenues:  
Sempra California$1,353 $1,186 $5,152 $4,750 
Sempra Infrastructure15 15 59 63 
Segment totals1,368 1,201 5,211 4,813 
Eliminations and adjustments
(5)(6)(16)(15)
Total$1,363 $1,195 $5,195 $4,798 
Cost of natural gas(1):
 
Sempra California$205 $97 $871 $777 
Sempra Infrastructure6 4 21 18 
Segment totals211 101 892 795 
Eliminations and adjustments
(1)(2)(6)(5)
Total$210 $99 $886 $790 
(1)    Excludes depreciation and amortization, which are presented separately on Sempra’s Condensed Consolidated Statements of Operations.

In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s natural gas revenues increased by $168 million (14%) driven by Sempra California, which included:
▪$122 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $7 million lower authorized cost of capital
▪$108 million increase in cost of natural gas sold, which we discuss below
▪$58 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax (expense) benefit. Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
Offset by:
▪$65 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$51 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax (expense) benefit
In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s cost of natural gas increased by $111 million driven by Sempra California, primarily due to higher average natural gas prices.
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In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s natural gas revenues increased by $397 million (8%) driven by Sempra California, which included:
▪$430 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $28 million lower authorized cost of capital
▪$103 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax (expense) benefit. Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$94 million increase in cost of natural gas sold, which we discuss below
▪$67 million higher revenues associated with refundable programs, which are fully offset in O&M
▪$14 million regulatory award approved by the CPUC in 2025
▪$14 million higher revenues from higher non-service components of net periodic benefit cost, which fully offsets in other income, net
Offset by:
▪$206 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$51 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax (expense) benefit
▪$29 million lower revenues from disallowed regulatory recovery of COVID-19 costs
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s cost of natural gas increased by $96 million (12%) driven by Sempra California, which included:
▪$112 million higher average natural gas prices
Offset by:
▪$18 million lower volumes driven by weather
Utilities: Electric Revenues and Cost of Electric Fuel and Purchased Power
Our utilities revenues include electric revenues at Sempra California, substantially all of which is at SDG&E. Intercompany revenues are eliminated in Sempra’s Condensed Consolidated Statements of Operations.
SDG&E operates under a regulatory framework that permits it 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.
Utility cost of electric fuel and purchased power includes utility-owned generation, power purchased from third parties, and net power purchases and sales to/from the California ISO.
UTILITIES: ELECTRIC REVENUES AND COST OF ELECTRIC FUEL AND PURCHASED POWER
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra:
Electric revenues:
Sempra California$1,260 $1,070 $3,352 $3,272 
Eliminations and adjustments— (1)(2)(3)
Total
$1,260 $1,069 $3,350 $3,269 
Cost of electric fuel and purchased power(1):
Sempra California$135 $(5)$314 $277 
Eliminations and adjustments(13)(13)(49)(50)
Total
$122 $(18)$265 $227 
(1)    Excludes depreciation and amortization, which are presented separately on Sempra’s Condensed Consolidated Statements of Operations.
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In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s electric revenues increased by $191 million (18%) driven by Sempra California, which included:
▪$140 million increase in cost of electric fuel and purchased power, which we discuss below
▪$40 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $6 million lower authorized cost of capital
▪$15 million higher revenues from incremental and balanced capital projects offset by certain projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$12 million higher revenues from transmission operations
Offset by:
▪$19 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax (expense) benefit
▪$7 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax (expense) benefit
In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s cost of electric fuel and purchased power increased by $140 million driven by Sempra California, which included:
▪$140 million higher purchased power primarily due to change in excess capacity sales and tolling agreements
▪$30 million lower sales to the California ISO due to lower market prices
Offset by:
▪$28 million lower purchased power from the California ISO due to lower market prices and lower customer demand from departing load now served by CCAs
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s electric revenues increased by $81 million (2%) driven by Sempra California, which included:
▪$87 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $15 million lower authorized cost of capital
▪$37 million increase in cost of electric fuel and purchased power, which we discuss below
▪$29 million higher revenues from incremental and balanced capital projects offset by certain projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$25 million higher revenues from transmission operations
Offset by:
▪$74 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax (expense) benefit
▪$19 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax (expense) benefit
▪$9 million lower revenues associated with refundable programs, which are fully offset in O&M
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s cost of electric fuel and purchased power increased by $38 million (17%) driven by Sempra California, which included:
▪$67 million higher purchased power primarily due to tolling agreements and change in excess capacity sales
▪$45 million lower sales to the California ISO due to lower market prices
Offset by:
▪$72 million lower purchased power from the California ISO due to lower market prices and lower customer demand from departing load now served by CCAs
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Energy-Related Businesses: Revenues and Cost of Sales
ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra:
Revenues:  
Sempra Infrastructure
$540 $523 $1,452 $1,403 
Parent and other(1)
(12)(11)(44)(43)
Total
$528 $512 $1,408 $1,360 
Cost of sales(2):
  
Sempra Infrastructure$117 $134 $321 $297 
(1)    Includes eliminations of intercompany activity.
(2)    Excludes depreciation and amortization, which are presented separately on Sempra’s Condensed Consolidated Statements of Operations.

In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s revenues from energy-related businesses increased by $16 million (3%) primarily due to:
▪$39 million from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
◦$90 million driven by higher natural gas prices and higher volumes associated with optimization of transport and storage contracts
Offset by:
◦$60 million from $50 million unrealized losses in 2025 compared to $10 million unrealized gains in 2024 on commodity derivatives
▪$18 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement
Offset by:
▪$30 million lower transportation revenues driven by a customer’s early termination of firm transportation agreements
▪$8 million from TdM due to lower power prices and lower volumes
In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s cost of sales from energy-related businesses decreased by $17 million (13%) primarily due to $19 million lower LNG purchases offset by higher natural gas purchases related to asset and supply optimization.
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s revenues from energy-related businesses increased by $48 million (4%) primarily due to:
▪$53 million higher revenues driven by satisfaction of performance obligations related to customer payments received in advance from a contract modification in December 2024 on an LNG storage and regasification agreement
▪$51 million from asset and supply optimization from contracts to sell natural gas and LNG to third parties, including:
◦$75 million driven by higher natural gas prices and higher volumes associated with optimization of transport and storage contracts
◦$22 million primarily from higher diversion fees due to higher natural gas prices
Offset by:
◦$45 million from higher unrealized losses on commodity derivatives
▪$15 million higher revenues in 2025 due to the commencement of commercial operations at the Topolobampo marine terminal in June 2024
Offset by:
▪$30 million lower transportation revenues driven by a customer’s early termination of firm transportation agreements
▪$15 million from TdM mainly due to lower volumes and lower power prices
▪$13 million from lower power prices from solar power generation assets and lower volumes from wind power generation assets
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s cost of sales from energy-related businesses increased by $24 million (8%) primarily due to $24 million driven by higher natural gas purchases offset by lower LNG purchases related to asset and supply optimization.
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Operation and Maintenance
OPERATION AND MAINTENANCE
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
Sempra:
Sempra California$1,047 $1,080 $3,222 $3,190 
Sempra Texas Utilities1 — 4 4 
Sempra Infrastructure257 218 644 616 
Segment totals1,305 1,298 3,870 3,810 
Parent and other(1)
44 28 61 61 
Total$1,349 $1,326 $3,931 $3,871 
(1)    Includes eliminations of intercompany activity.

In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s O&M increased by $23 million (2%) primarily due to:
▪$39 million increase at Sempra Infrastructure due to:
◦$18 million from higher provisions for expected credit losses
◦$17 million primarily due to higher expenses in 2025 in advance of ECA LNG Phase 1 commencing commercial operations and higher maintenance expenses
◦$8 million higher development costs and certain non-capitalized expenses from projects under construction
▪$16 million increase at Parent and other primarily due to non-recoverable insurance claims in 2025
Offset by:
▪$33 million decrease at Sempra California primarily due to lower non-refundable operating costs
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s O&M increased by $60 million (2%) primarily due to:
▪$32 million increase at Sempra California due to:
◦$58 million higher expenses associated with refundable programs, which costs are recovered in revenue
Offset by:
◦$29 million lower non-refundable operating costs
▪ $28 million increase at Sempra Infrastructure due to:
◦$22 million primarily due to higher expenses in 2025 in advance of ECA LNG Phase 1 commencing commercial operations and higher maintenance expenses
◦$12 million higher development costs and certain non-capitalized expenses from projects under construction
▪Parent and other was consistent with the prior year due to:
◦$22 million due to non-recoverable insurance claims in 2025
Offset by:
◦$10 million from $5 million compensation benefit in 2025 compared to $5 million compensation expense in 2024
◦$4 million due to lower deferred compensation expense
Other Income, Net
In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s other income, net, decreased by $16 million (25%) to $49 million primarily due to:
▪$19 million higher non-service components of net periodic benefit cost primarily at Sempra California
▪$7 million lower investment gains on dedicated assets in support of our employee nonqualified benefit plan and deferred compensation plan at Parent and other
Offset by:
▪$7 million from $3 million gains in 2025 compared to $4 million losses in 2024 from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions driven by other foreign currency transactional effects at Sempra Infrastructure
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In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s other income, net, increased by $5 million (3%) to $199 million primarily due to:
▪$16 million higher AFUDC equity at Sempra Infrastructure
▪$12 million from $8 million gains in 2025 compared to $4 million losses in 2024 from impacts associated with interest rate and foreign exchange instruments and foreign currency transactions driven by other foreign currency transactional effects primarily at Sempra Infrastructure
▪$9 million higher net interest income on regulatory balancing accounts at Sempra California
Offset by:
▪$23 million higher non-service components of net periodic benefit cost primarily at Sempra California
▪$7 million reduction in regulatory interest from disallowed regulatory recovery of COVID-19 costs at Sempra California
Interest Income
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s interest income increased by $18 million (38%) to $65 million primarily due to a $14 million change in the fair value of the Support Agreement at Sempra Infrastructure.
Interest Expense
In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s interest expense increased by $75 million (23%) to $403 million primarily due to:
▪$39 million at Parent and other from higher debt balances from debt issuances
▪$21 million at Sempra California from higher debt balances from debt issuances
▪$16 million at Sempra Infrastructure primarily from higher interest expense related to a customer’s early termination of firm transportation agreements
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s interest expense increased by $251 million (27%) to $1.2 billion due to:
▪$104 million at Parent and other from higher debt balances from debt issuances offset by higher capitalization of interest expense in 2025 from projects under construction at Sempra Infrastructure
▪$87 million at Sempra Infrastructure primarily from $60 million in unrealized losses in 2025 on interest rate swaps related to the PA LNG Phase 1 project and higher interest expense related to a customer’s early termination of firm transportation agreements offset by higher capitalization of interest expense in 2025 from projects under construction
▪$60 million at Sempra California from higher debt balances from debt issuances
Income Taxes
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
Three months ended September 30,Nine months ended September 30,
2025202420252024
Sempra:
Income tax expense (benefit)$482 $(105)$711 $(63)
Income before income taxes and equity earnings$160 $200 $1,109 $1,213 
Equity earnings, before income tax(1)
133 132 443 426 
Pretax income
$293 $332 $1,552 $1,639 
Effective income tax rate165 %(32)%46 %(4)%
(1)    We discuss how we recognize equity earnings in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

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 U.S. 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.
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In the three months ended September 30, 2025 compared to the same period in 2024, Sempra had an income tax expense in 2025 compared to an income tax benefit in 2024 primarily due to:
▪$514 million net income tax expense in 2025 as a result of management’s decision to classify SI Partners as held for sale, comprised of the following:
◦$705 million income tax expense to adjust deferred income tax liabilities primarily related to outside basis differences in our investment in SI Partners
◦$153 million income tax expense for changes in state income tax apportionment
Offset by:
◦$344 million income tax benefit from changes to a valuation allowance against certain tax credit carryforwards
▪$123 million from $45 million income tax expense in 2025 compared to $78 million income tax benefit in 2024 from foreign currency and inflation effects on our monetary positions in Mexico
▪$78 million income tax expense in 2025 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA
▪$30 million income tax benefit in 2024 from an outside basis difference in a domestic partnership investment
Offset by:
▪higher income tax benefit from flow-through items, including $73 million income tax benefit in 2025 from the election to accelerate self-developed software deductions, which we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements
▪higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra had an income tax expense in 2025 compared to an income tax benefit in 2024 primarily due to:
▪$552 million net income tax expense in 2025 as a result of management’s decision to classify SI Partners and Ecogas as held for sale, comprised of the following:
◦$705 million income tax expense to adjust deferred income tax liabilities primarily related to outside basis differences in our investment in SI Partners
◦$153 million income tax expense for changes in state income tax apportionment
◦$38 million income tax expense due to the recognition of a Mexican deferred tax liability on our outside basis differences in Ecogas
Offset by:
◦$344 million income tax benefit from changes to a valuation allowance against certain tax credit carryforwards
▪$368 million from $157 million income tax expense in 2025 compared to $211 million income tax benefit in 2024 from foreign currency and inflation effects on our monetary positions in Mexico
▪$78 million income tax expense in 2025 from changes to a valuation allowance against foreign tax credits that were carried forward from the implementation of the TCJA
▪$30 million income tax benefit in 2024 from an outside basis difference in a domestic partnership investment
Offset by:
▪higher income tax benefit from flow-through items, including $73 million income tax benefit in 2025 from the election to accelerate self-developed software deductions
▪higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
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 Note 1 of the Notes to Condensed Consolidated Financial Statements in this report and Notes 1 and 7 of the Notes to Consolidated Financial Statements in the Annual Report for further details about our accounting for income taxes and items subject to flow-through treatment.
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Equity Earnings
In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s equity earnings increased by $18 million (4%) to $472 million primarily due to:
▪$45 million at Oncor Holdings driven by:
◦overall higher revenues primarily attributable to:
•rate updates to reflect increases in invested capital
•increase due to Oncor’s SRP and the UTM
Offset by:
◦higher interest expense and depreciation expense associated with increases in invested capital
◦higher O&M
Offset by:
▪$24 million at IMG due to an income tax expense in 2025 compared to an income tax benefit in 2024 primarily from foreign currency and inflation effects
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s equity earnings decreased by $45 million (4%) remaining at $1.2 billion primarily due to:
▪$74 million at IMG due to an income tax expense in 2025 compared to an income tax benefit in 2024 primarily from foreign currency and inflation effects
Offset by:
▪$19 million at Cameron LNG JV primarily from higher maintenance revenues and lower interest expense
▪$15 million at Oncor Holdings driven by:
◦overall higher revenues primarily attributable to:
•rate updates to reflect increases in invested capital
•increase due to Oncor’s SRP and the establishment of the UTM
•customer growth
Offset by:
◦higher interest expense and depreciation expense associated with increases in invested capital
◦higher O&M
Earnings Attributable to Noncontrolling Interests
In the three months ended September 30, 2025 compared to the same period in 2024, Sempra’s earnings attributable to NCI decreased by $55 million to $55 million primarily due to a decrease in SI Partners subsidiaries’ net income driven by foreign currency and inflation effects on our monetary positions in Mexico.
In the nine months ended September 30, 2025 compared to the same period in 2024, Sempra’s earnings attributable to NCI decreased by $222 million to $103 million primarily due to a decrease in SI Partners subsidiaries’ net income driven by foreign currency and inflation effects on our monetary positions in Mexico and unrealized losses in 2025 from interest rate swaps related to the PA LNG Phase 1 project.

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. We discuss further the impact of foreign currency and inflation rates on results of operations, including impacts on income taxes and related hedging activity, in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” in the Annual Report.
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. In the three months and nine months ended September 30, 2025 compared to the same periods in 2024, the change in our earnings as a result of foreign currency translation rates was lower by $1 million.
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Transactional Impacts
Income statement activities at our foreign operations and their equity method investments are also impacted by transactional gains and losses, a summary of which is shown in the table below:
TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION EFFECTS
(Dollars in millions)
 Total reported amountsTransactional gains (losses) included in reported amounts
 Three months ended September 30,
 2025202420252024
Other income, net$49 $65 $3 $(4)
Income tax (expense) benefit(482)105 (45)78 
Equity earnings472 454 (6)26 
Net income150 759 (48)100 
Earnings attributable to noncontrolling interests(55)(110)16 (33)
Earnings attributable to common shares77 638 (32)67 
 Nine months ended September 30,
 2025202420252024
Other income, net$199 $194 $8 $(4)
Income tax (expense) benefit(711)63 (157)211 
Equity earnings1,190 1,235 (33)56 
Net income1,588 2,511 (182)263 
Earnings attributable to noncontrolling interests(103)(325)61 (85)
Earnings attributable to common shares1,444 2,152 (121)178 

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SDGE logo.jpg
We discuss herein SDG&E’s results of operations and significant changes in earnings, revenues and costs for the three months (Q3) and nine months (YTD) ended September 30, 2025 compared to the same period in 2024.
Due to the delay in the issuance of the CPUC’s FD in the SDG&E 2024 GRC, SDG&E recorded revenues in the first three quarters of 2024 based on levels authorized for 2023 under the 2019 GRC. In December 2024, the CPUC approved an FD in the 2024 GRC, effective retroactive to January 1, 2024, for which SDG&E recorded the retroactive impacts in the fourth quarter of 2024. SDG&E’s authorized base revenues for the first three quarters of 2025 are based on the revenues authorized for the 2024 test year plus the amount authorized for attrition for 2025. We provide additional information on the 2024 GRC FD in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
(Dollars in millions)
460
In the three months ended September 30, 2025 compared to the same period in 2024, the increase in earnings of $63 million (24%) was primarily due to:
▪$53 million higher income tax benefits primarily from flow-through items, including impacts from the election to accelerate self-developed software deductions, and from the resolution of prior year income tax items
▪$15 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $5 million lower authorized cost of capital. In the first three quarters of 2024, SDG&E recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$4 million higher electric transmission margin
▪$4 million higher net regulatory interest income
Offset by:
▪$8 million higher net interest expense
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In the nine months ended September 30, 2025 compared to the same period in 2024, the increase in earnings of $110 million (16%) was primarily due to:
▪$60 million higher income tax benefits primarily from flow-through items, including impacts from the election to accelerate self-developed software deductions and gas repairs tax benefits (which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD), and from the resolution of prior year income tax items
▪$49 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $14 million lower authorized cost of capital. In the first three quarters of 2024, SDG&E recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$10 million higher net regulatory interest income
▪$7 million higher electric transmission margin
Offset by:
▪$22 million higher net interest expense
SIGNIFICANT CHANGES IN REVENUES AND COSTS
Electric Revenues and Cost of Electric Fuel and Purchased Power
In the three months ended September 30, 2025 compared to the same period in 2024, SDG&E’s electric revenues increased by $191 million (18%) to $1.3 billion primarily due to:
▪$140 million increase in cost of electric fuel and purchased power, which we discuss below
▪$40 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $6 million lower authorized cost of capital
▪$15 million higher revenues from incremental and balanced capital projects offset by certain projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$12 million higher revenues from transmission operations
Offset by:
▪$19 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)
▪$7 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax benefit (expense)
In the three months ended September 30, 2025 compared to the same period in 2024, SDG&E’s cost of electric fuel and purchased power increased by $140 million to $135 million primarily due to:
▪$140 million higher purchased power primarily due to change in excess capacity sales and tolling agreements
▪$30 million lower sales to the California ISO due to lower market prices
Offset by:
▪$28 million lower purchased power from the California ISO due to lower market prices and lower customer demand from departing load now served by CCAs
In the nine months ended September 30, 2025 compared to the same period in 2024, SDG&E’s electric revenues increased by $80 million (2%) to $3.4 billion primarily due to:
▪$87 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $15 million lower authorized cost of capital
▪$37 million increase in cost of electric fuel and purchased power, which we discuss below
▪$29 million higher revenues from incremental and balanced capital projects offset by certain projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$25 million higher revenues from transmission operations
Offset by:
▪$74 million lower regulatory revenues from higher ITCs from standalone energy storage projects, which are offset in income tax benefit (expense)
▪$19 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)
▪$9 million lower revenues associated with refundable programs, which are fully offset in O&M
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In the nine months ended September 30, 2025 compared to the same period in 2024, SDG&E’s cost of electric fuel and purchased power increased by $37 million (13%) to $314 million primarily due to:
▪$67 million higher purchased power primarily due to tolling agreements and change in excess capacity sales
▪$45 million lower sales to the California ISO due to lower market prices
Offset by:
▪$72 million lower purchased power from the California ISO due to lower market prices and lower customer demand from departing load now served by CCAs
Natural Gas Revenues and Cost of Natural Gas
In the three months ended September 30, 2025 and 2024, SDG&E’s average cost of natural gas per thousand cubic feet was $6.30 and $5.61, respectively. In the nine months ended September 30, 2025 and 2024, SDG&E’s average cost of natural gas per thousand cubic feet was $5.16 and $5.19, respectively. The average cost of natural gas sold at SDG&E is impacted by market prices, as well as transportation, tariff and other charges.
In the three months ended September 30, 2025 compared to the same period in 2024, SDG&E’s natural gas revenues increased by $46 million (27%) to $216 million primarily due to:
▪$25 million higher revenues associated with refundable programs, which are fully offset in O&M
▪$16 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax benefit (expense). Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$15 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $1 million lower authorized cost of capital
▪$6 million increase in cost of natural gas sold, which we discuss below
Offset by:
▪$13 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
In the three months ended September 30, 2025 compared to the same period in 2024, SDG&E’s cost of natural gas increased by $6 million (16%) to $44 million primarily due to higher average natural gas prices.
In the nine months ended September 30, 2025 compared to the same period in 2024, SDG&E’s natural gas revenues increased by $105 million (15%) to $800 million primarily due to:
▪$65 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $4 million lower authorized cost of capital
▪$44 million higher revenues associated with refundable programs, which are fully offset in O&M
▪$24 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax benefit (expense). Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
Offset by:
▪$27 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
Operation and Maintenance
In the three months and nine months ended September 30, 2025 compared to the same periods in 2024, SDG&E’s O&M increased by $31 million (7%) to $451 million and $40 million (3%) remaining at $1.3 billion, respectively, primarily due to higher expenses associated with refundable programs, which costs are recovered in revenue.
Other Income, Net
In the three months and nine months ended September 30, 2025 compared to the same periods in 2024, SDG&E’s other income, net, increased by $2 million (7%) to $32 million and $17 million (20%) to $103 million, respectively, primarily due to higher net interest income on regulatory balancing accounts.
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Income Taxes
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
SDG&E:
Income tax (benefit) expense$(33)$15 $(12)$89 
Income before income taxes$291 $276 $768 $759 
Effective income tax rate(11)%5 %(2)%12 %
In the three months and nine months ended September 30, 2025 compared to the same periods in 2024, SDG&E had an income tax benefit in 2025 compared to an income tax expense in 2024, respectively, primarily due to:
▪higher income tax benefit from flow-through items, including $26 million income tax benefit in 2025 from the election to accelerate self-developed software deductions, which we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements
▪higher income tax benefit in 2025 from higher ITCs from standalone energy storage projects
SoCalGas logo 20231231form10k.jpg
We discuss herein SoCalGas’ results of operations and significant changes in earnings (losses), revenues and costs for the three months (Q3) and nine months (YTD) ended September 30, 2025 compared to the same period in 2024.
Due to the delay in the issuance of the CPUC’s FD in the SoCalGas 2024 GRC, SoCalGas recorded revenues in the first three quarters of 2024 based on levels authorized for 2023 under the 2019 GRC. In December 2024, the CPUC approved an FD in the 2024 GRC, effective retroactive to January 1, 2024, for which SoCalGas recorded the retroactive impacts in the fourth quarter of 2024. SoCalGas’ authorized base revenues for the first three quarters of 2025 are based on the revenues authorized for the 2024 test year plus the amount authorized for attrition for 2025. We provide additional information on the 2024 GRC FD in Note 4 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
(Dollars in millions)
473
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In the three months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ earnings were $46 million compared to losses of $14 million primarily due to:
▪$39 million higher income tax benefits primarily from the resolution of prior year income tax items and from flow-through items, including impacts from the election to accelerate self-developed software deductions
▪$32 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $4 million lower authorized cost of capital. In the first three quarters of 2024, SoCalGas recorded CPUC-authorized base revenues based on 2023 authorized levels
Offset by:
▪$8 million higher net interest expense
In the nine months ended September 30, 2025 compared to the same period in 2024, the increase in earnings of $98 million (21%) was primarily due to:
▪$74 million higher income tax benefits primarily from flow-through items, including gas repairs tax benefits (which in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD) and impacts from the election to accelerate self-developed software deductions, and from the resolution of prior year income tax items
▪$70 million higher CPUC base operating margin, net of operating expenses including higher depreciation and $17 million lower authorized cost of capital. In the first three quarters of 2024, SoCalGas recorded CPUC-authorized base revenues based on 2023 authorized levels
▪$10 million regulatory award approved by the CPUC in 2025
Offset by:
▪$26 million higher net interest expense
▪$25 million from disallowed regulatory recovery of COVID-19 costs
SIGNIFICANT CHANGES IN REVENUES AND COSTS
Natural Gas Revenues and Cost of Natural Gas
In the three months ended September 30, 2025 and 2024, SoCalGas’ average cost of natural gas per thousand cubic feet was $3.96 and $1.82, respectively. In the nine months ended September 30, 2025 and 2024, SoCalGas’ average cost of natural gas per thousand cubic feet was $3.65 and $3.14, respectively. The average cost of natural gas sold at SoCalGas is impacted by market prices, as well as transportation and other charges.
In the three months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ natural gas revenues increased by $127 million (12%) to $1.2 billion primarily due to:
▪$107 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $6 million lower authorized cost of capital
▪$100 million increase in cost of natural gas sold, which we discuss below
▪$42 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax benefit (expense). Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
Offset by:
▪$52 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$48 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)
▪$24 million lower revenues associated with refundable programs, which are fully offset in O&M
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In the three months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ cost of natural gas increased by $100 million to $182 million primarily due to higher average natural gas prices.
In the nine months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ natural gas revenues increased by $301 million (7%) to $4.5 billion primarily due to:
▪$365 million higher CPUC-authorized base revenues, including certain incremental and balanced capital projects that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD offset by $24 million lower authorized cost of capital
▪$88 million increase in cost of natural gas sold, which we discuss below
▪$79 million higher regulatory revenues, including gas repairs tax benefits, which are offset in income tax benefit (expense). Gas repairs tax benefits in the first three quarters of 2024 were recorded as a regulatory liability that was released in the fourth quarter of 2024 as a result of the 2024 GRC FD
▪$23 million higher revenues associated with refundable programs, which are fully offset in O&M
▪$14 million regulatory award approved by the CPUC in 2025
▪$13 million higher revenues from higher non-service components of net periodic benefit cost, which fully offsets in other (expense) income, net
Offset by:
▪$179 million lower revenues from incremental and balanced capital projects, including those that are now in CPUC-authorized base revenues as a result of the 2024 GRC FD and lower authorized cost of capital
▪$48 million lower regulatory revenues associated with impacts from the election to accelerate self-developed software deductions, which are offset in income tax benefit (expense)
▪$29 million lower revenues from disallowed regulatory recovery of COVID-19 costs
In the nine months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ cost of natural gas increased by $88 million (13%) to $749 million due to:
▪$105 million higher average natural gas prices
Offset by:
▪$17 million lower volumes driven by weather
Operation and Maintenance
In the three months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ O&M decreased by $55 million (8%) to $623 million due to:
▪$31 million lower non-refundable operating costs
▪$24 million lower expenses associated with refundable programs, which costs are recovered in revenue
In the nine months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ O&M increased by $4 million remaining at $2.0 billion due to:
▪$23 million higher expenses associated with refundable programs, which costs are recovered in revenue
Offset by:
▪$19 million lower non-refundable operating costs
Other (Expense) Income, Net
In the three months ended September 30, 2025 compared to the same period in 2024, SoCalGas had $3 million of other expense, net, in 2025 compared to $13 million of other income, net, in 2024 primarily due to higher non-service components of net periodic benefit cost.
In the nine months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ other income, net, decreased by $36 million (49%) to $37 million primarily due to:
▪$22 million higher non-service components of net periodic benefit cost
▪$7 million reduction in regulatory interest from disallowed regulatory recovery of COVID-19 costs
▪$5 million lower net interest income on regulatory balancing accounts
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Income Taxes
INCOME TAX EXPENSE (BENEFIT) AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
 Three months ended September 30,Nine months ended September 30,
 2025202420252024
SoCalGas:
Income tax (benefit) expense$(95)$(52)$(51)$1 
(Loss) income before income taxes$(49)$(66)$523 $477 
Effective income tax rate194 %79 %(10)%— %
In the three months ended September 30, 2025 compared to the same period in 2024, SoCalGas’ income tax benefit increased by $43 million primarily due to:
▪higher income tax benefit from flow-through items, including $47 million income tax benefit in 2025 from the election to accelerate self-developed software deductions, which we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements
Offset by:
▪$19 million lower income tax benefit from the resolution of prior year income tax items, including benefits that are flowed to customers and recorded as a regulatory liability
In the nine months ended September 30, 2025 compared to the same period in 2024, SoCalGas had an income tax benefit in 2025 compared to an income tax expense in 2024 primarily due to:
▪higher income tax benefit from flow-through items, including $47 million income tax benefit in 2025 from the election to accelerate self-developed software deductions
Offset by:
▪$19 million lower income tax benefit from the resolution of prior year income tax items, including benefits that are flowed to customers and recorded as a regulatory liability
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CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
Sempra
Capital Recycling Program
We regularly review our portfolio of assets with a view toward allocating capital to the businesses we believe can further improve shareholder value. Following a comprehensive strategic review of our businesses and asset portfolio by our board of directors and management over the past year, in September 2025, we entered into an agreement to sell a 45% equity interest in SI Partners to the KKR Partners for $9.99 billion, subject to adjustments. Also in June 2025, we committed to a formal plan to sell Ecogas and are actively marketing and pursuing the sale of these assets. We expect to complete the sales in the second or third quarter of 2026. We discuss these sales further in Note 6 of the Notes to Condensed Consolidated Financial Statements and below in “Sempra Infrastructure.”
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 which may include issuing debt securities and obtaining term loans
▪selling assets or equity interests in our subsidiaries or development projects, including the planned sale of a portion of our equity interest in SI Partners
▪issuing equity securities under our ATM program or other offerings
▪funding from NCI or CRNCI owners
We believe that these cash flow sources, combined with available funds, will be adequate to fund our operations in both the short-term and long-term, including to:
▪finance capital expenditures
▪repay debt
▪fund dividends
▪fund contractual and other obligations and otherwise meet liquidity requirements
▪fund capital contribution requirements
▪fund new business or asset acquisitions
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 or otherwise raise money at market rates from commercial banks, under existing revolving credit facilities, through public offerings of debt or equity securities (including under our ATM program or other offerings), or through private placements of debt supported by our revolving credit facilities in the case of commercial paper. However, our ability to access these markets or obtain credit from commercial banks outside of our committed revolving credit facilities could become materially constrained if economic conditions worsen or disruptions to or volatility in these markets increase. In addition, our financing activities, actions by credit rating agencies and prevailing interest rates, as well as many other factors, could negatively affect the availability and cost of both short-term and long-term debt and equity financing. Also, cash flows from operations may be impacted by the timing and outcomes of regulatory proceedings, commencement and completion of, and potential cost overruns for, large projects and other material events. If cash flows from operations were to be significantly reduced or we were unable to borrow or obtain other financing 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.
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Redemption of Series C Preferred Stock
As we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements, in September 2025, we provided notice of the redemption of all 900,000 issued and outstanding shares of our series C preferred stock for a redemption price in cash of $1,000 per share. On October 15, 2025, we effected and paid $900 million for the redemption using proceeds received from our August 2025 issuance of junior subordinated notes and short-term debt, which we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements.
ATM Program and Forward Sales Agreements
In November 2024, we established an ATM program providing for the offer and sale of shares of Sempra common stock having an aggregate gross sales price of up to $3.0 billion through agents acting as our sales agents or as forward sellers or directly to the agents as principals. The shares may be offered and sold in amounts and at times to be determined by us from time to time.
Since establishing the ATM program, an aggregate of 4,996,591 shares have been sold under the forward sale agreements described below with an average initial forward price of $83.175. Such average initial forward price is weighted to take into account the number of shares sold under each forward sale agreement.
In the fourth quarter of 2024, we entered into a forward sale agreement under the ATM program for the sale of 2,909,274 shares of Sempra common stock that remain subject to future settlement. At the initial forward price of $92.1546 per share, the net proceeds from this forward sale agreement if we elect full physical settlement would be approximately $268 million. At September 30, 2025, a total of 2,909,274 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than June 30, 2026.
In the first quarter of 2025, we entered into a forward sale agreement under the ATM program for the sale of 2,087,317 shares of Sempra common stock that remain subject to future settlement. At the initial forward price of $70.6593 per share, the net proceeds from this forward sale agreement if we elect full physical settlement would be approximately $147 million. At September 30, 2025, a total of 2,087,317 shares of Sempra common stock remain subject to future settlement under this forward sale agreement, which may be settled on one or more dates specified by us no later than March 31, 2027.
We did not initially receive any proceeds from the sale of shares pursuant to the forward sale agreements. Although we may settle the forward sale agreements entirely by the physical delivery of shares of our common stock in exchange for cash proceeds, we may, subject to certain conditions, elect cash settlement or net share settlement for all or a portion of our obligations under the forward sale agreements.
At September 30, 2025, approximately $2.6 billion of common stock remained available for sale under the ATM program.
We further discuss these activities, including the intended use of proceeds and effect on diluted EPS, in Note 11 of the Notes to Condensed Consolidated Financial Statements.
Available Funds
Our committed lines of credit provide liquidity and support commercial paper. Sempra, SDG&E and SoCalGas each has a committed line of credit expiring in 2030. Sempra Infrastructure has five committed lines of credit expiring on various dates from 2026 through 2030 and an uncommitted line of credit expiring in 2026, which are included in the held for sale disposal group but remain legally accessible and a source of available credit until the sale of a portion of our equity interest in SI Partners closes.
AVAILABLE FUNDS AT SEPTEMBER 30, 2025
(Dollars in millions)
 SempraSDG&ESoCalGas
Unrestricted cash and cash equivalents(1)
$131 $— $— 
Available unused credit(2)
8,632 1,473 789 
(1)    Sempra includes $69 held in non-U.S. jurisdictions, which is included in $126 that is classified as Assets Held for Sale in the Sempra Condensed Consolidated Balance Sheet. We discuss repatriation in Note 7 of the Notes to Consolidated Financial Statements in the Annual Report.
(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 Condensed Consolidated Financial Statements. Because our commercial paper programs are supported by these lines, we reflect the amount of commercial paper outstanding and any letters of credit outstanding as a reduction to the available unused credit.
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Short-Term Borrowings
We use short-term debt primarily to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures or acquisitions. SDG&E and SoCalGas use short-term debt primarily to meet working capital needs or to help fund event-specific costs. Commercial paper, term loans and lines of credit were our primary sources of short-term debt funding in the first nine months of 2025.
We discuss our short-term debt activities in Note 7 of the Notes to Condensed Consolidated Financial Statements and below in “Sources and Uses of Cash.”
Long-Term Debt Activities
Significant issuances of and payments on long-term debt in the first nine months of 2025 included the following:
LONG-TERM DEBT ISSUANCES AND PAYMENTS
(Dollars in millions)
Issuances:Amount at issuanceMaturity
Sempra 6.375% junior subordinated notes$800 2056
SDG&E 5.40% first mortgage bonds850 2035
SoCalGas 5.45% first mortgage bonds600 2035
SoCalGas 6.00% first mortgage bonds500 2055
Sempra Infrastructure variable rate notes (ECA LNG Phase 1 project)392 2027
Sempra Infrastructure variable rate term loan (PA LNG Phase 1 project)2,130 2030
Sempra Infrastructure 6.27% senior secured notes (PA LNG Phase 1 project)750 2042
Sempra Infrastructure 6.32% senior secured notes (PA LNG Phase 1 project)250 2042
Payments:PaymentsMaturity
SoCalGas 3.20% first mortgage bonds$350 2025
Sempra 3.30% notes750 2025
Sempra Infrastructure variable rate notes (ECA LNG Phase 1 project)236 2027
Sempra Infrastructure variable rate term loan (PA LNG Phase 1 project)983 2030
Sempra Infrastructure loan at variable rates (4.03% after floating-to-fixed rate swap effective 2019) payable June 15, 2022 through November 19, 203425 2034
We discuss our long-term debt activities, including the use of proceeds on long-term debt issuances, in Note 7 of the Notes to Condensed Consolidated Financial Statements.
Credit Ratings
We provide additional information about the credit ratings of Sempra, SDG&E and SoCalGas in “Part I – Item 1A. Risk Factors” and “Part II – Item 2. MD&A – Capital Resources and Liquidity” in the Annual Report.
The credit ratings of Sempra, SDG&E and SoCalGas remained at investment grade levels in the first nine months of 2025.
CREDIT RATINGS AT SEPTEMBER 30, 2025
  
 SempraSDG&ESoCalGas
Moody’sBaa2 with a negative outlookA3 with a stable outlookA2 with a stable outlook
S&PBBB+ with a negative outlookBBB+ with a stable outlookA- with a stable outlook
FitchBBB+ with a stable outlookBBB+ with a stable outlookA with a stable outlook
A downgrade of Sempra’s or any of its subsidiaries’ credit ratings or rating outlooks may, depending on the severity, result in the imposition of new 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 or equity 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” in the Annual Report.
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Sempra has agreed that, if the credit rating of Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT. Oncor’s senior secured debt was rated A2, A and A at Moody’s, S&P and Fitch, respectively, at September 30, 2025.
Pillar Two
The Organization for Economic Cooperation and Development has introduced a framework known as “Pillar Two” to implement a global minimum effective tax rate of 15% in every jurisdiction (generally, every country) in which a company does business. Many aspects of the Pillar Two framework became effective beginning in 2024. While it is uncertain whether the U.S. or Mexico will enact legislation to adopt the Pillar Two framework, other countries are in the process of introducing and enacting legislation to implement Pillar Two. We do not currently expect the Pillar Two framework to have a material effect 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 legislatures, litigation and the changing energy marketplace, as well as other matters described in this report and the Annual 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. SDG&E and SoCalGas manage their capital structures and pay dividends when appropriate and as approved by their respective boards of directors. On October 1, 2025, SDG&E declared dividends, and on October 3, 2025, paid dividends of $200 million to Enova Corporation and Enova Corporation paid corresponding dividends to Sempra.
SDG&E and SoCalGas have regulatory mechanisms to recover credit losses and thus record changes in the allowances for credit losses related to Accounts Receivable – Trade that are probable of recovery in regulatory accounts. Although SDG&E and SoCalGas have regulatory mechanisms to recover credit losses, delay in payments by customers impacts the timing of their cash flows.
As we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements, changes in regulatory 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.
CPUC GRC
As we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements, in December 2024, the CPUC approved an FD in the 2024 GRC for SDG&E and SoCalGas that authorizes SDG&E’s and SoCalGas’ revenue requirements for 2024 and attrition year adjustments for 2025 through 2027, inclusively.
Since the GRC FD is effective retroactive to January 1, 2024, SDG&E and SoCalGas recorded the retroactive impacts in the fourth quarter of 2024. The incremental revenue requirements associated with the period from January 1, 2024 through January 31, 2025 are being recovered in rates over an 18-month period that began on February 1, 2025.
Existing and Anticipated Requests for Recovery of Specified Safety, Maintenance and Reliability Investments. The GRC also provides SDG&E and SoCalGas with numerous mechanisms to seek cost recovery of specified projects and programs. We expect that the requests for cost recovery of these projects and programs, which remain subject to CPUC approval, may result in additional amounts of authorized revenue requirement. These projects and programs include (i) the Track 2 and Track 3 requests that we describe below, (ii) the ability to file advice letters to implement the revenue requirements associated with the costs of SDG&E’s Moreno compressor station project and SoCalGas’ Honor Rancho compressor station and customer information system replacement projects, which projects were all approved by the CPUC subject to applicable cost caps, and (iii) the opportunity to file separate applications for cost recovery of mobile home park and gas integrity management programs at both SDG&E and SoCalGas, advanced metering infrastructure replacements at SDG&E, and other projects and programs.
2024 GRC Track 2. In October 2023, SDG&E submitted a separate request to the CPUC in its 2024 GRC, known as a Track 2 request. This request seeks review and recovery of $1.5 billion of wildfire mitigation plan costs incurred from 2019 through 2022 that were in addition to amounts authorized in the 2019 GRC and not addressed in the 2024 GRC FD. SDG&E expects to receive a proposed decision for its Track 2 request by the end of 2025.
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Revenue requirements associated with the Track 2 request have been recorded in a regulatory account. In February 2024, the CPUC approved an interim cost recovery mechanism that permits SDG&E to recover in rates $194 million and $96 million of this regulatory account balance in 2024 and 2025, respectively. Such recovery of SDG&E’s wildfire mitigation plan regulatory account balance will be subject to refund, contingent on the reasonableness review decision for its Track 2 request.
2024 GRC Track 3. In April 2025, SDG&E and SoCalGas each submitted additional requests to the CPUC in the 2024 GRC, known as Track 3 requests. SDG&E submitted a request seeking review and recovery of $417 million of its wildfire mitigation plan costs incurred in 2023 that were in addition to the amounts authorized in the 2019 GRC and not addressed in the 2024 GRC. Additionally, SDG&E and SoCalGas submitted a combined request seeking review and recovery of $240 million and $499 million, respectively, of PSEP costs incurred from 2014 through 2019 and 2015 through 2020, respectively. SDG&E and SoCalGas expect to receive proposed decisions for their Track 3 requests in the first half of 2026.
Revenue requirements associated with the Track 3 requests have been recorded in regulatory accounts. SDG&E and SoCalGas are authorized interim rate recovery of up to 50% of the recorded PSEP regulatory account balance at the end of each year. Such interim rate recovery is subject to refund, contingent on the reasonableness review decision for their Track 3 requests.
CPUC Cost of Capital
In March 2025, SDG&E and SoCalGas each filed applications with the CPUC seeking to update their cost of capital for 2026 through 2028, subject to the CCM. SDG&E and SoCalGas expect to receive an FD by the end of 2025. We further discuss the cost of capital and CCM in Note 4 of the Notes to Condensed Consolidated Financial Statements.
SDG&E
Wildfire Fund and Continuation Account
2019 Wildfire Legislation. We describe the 2019 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 in the Annual Report.
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 2019 Wildfire Legislation in July 2019. In such a situation, SDG&E may recognize a reduction of its Wildfire Fund asset and record accelerated amortization against earnings when available coverage is reduced due to recoverable claims from any of the participating IOUs. The carrying value of SDG&E’s Wildfire Fund asset totaled $264 million at September 30, 2025.
In October 2025, a participating IOU publicly disclosed that it has received, or expects to receive, approximately $1.2 billion in aggregate reimbursements from the Wildfire Fund for eligible claims related to wildfires that occurred in 2019 and 2021. In the three months and nine months ended September 30, 2025, SDG&E reduced its Wildfire Fund asset by recording $2 million of accelerated amortization in O&M on Sempra’s and SDG&E’s Condensed Consolidated Statements of Operations.
Also in October 2025, another participating IOU publicly disclosed its intent to seek reimbursement from the Wildfire Fund for losses incurred and expected to be incurred in connection with a wildfire that remains under investigation, and for which the cause has not yet been conclusively determined. The administrator of the Wildfire Fund has confirmed that this wildfire qualifies as a “covered wildfire” for purposes of accessing the fund. The participating IOU has stated that it is currently unable to reasonably estimate a range of potential losses associated with this event. Accordingly, SDG&E is unable to estimate a range of potential loss resulting from any reduction in available coverage from the Wildfire Fund.
For existing claims or new claims based on any California electric IOUs’ assets determined to be a cause of fires, including fires of the size and scope of the Eaton fire, payments of these claims could have a material adverse effect on the Wildfire Fund, including potentially exhausting the fund, and 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.
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2025 Wildfire Legislation. We describe the 2025 Wildfire Legislation that was signed into law in September 2025 in Note 1 of the Notes to Condensed Consolidated Financial Statements. The 2025 Wildfire Legislation established, among other things, the Continuation Account, a new state-administered account with up to $18.0 billion of additional liquidity to reimburse catastrophic wildfire-related claims incurred by large California electric IOUs, including SDG&E, if the Wildfire Fund is depleted. The funds in the account would only be available for claims arising from wildfires that ignited on or after September 19, 2025. The 2025 Wildfire Legislation preserves key elements of the 2019 Wildfire Legislation, including cost recovery standards and requirements, a cap on liability in the event of a finding of imprudence by the CPUC, and continued access to wildfire claims liquidity through the new Continuation Account. All of California’s large electric IOUs, including SDG&E, have elected to participate in the Continuation Account.
If the Continuation Account becomes operative, it would be funded with a combination of $9.0 billion from ratepayer contributions and $9.0 billion from electric IOU shareholder contributions. Electric IOU shareholder contributions totaling $5.1 billion would be obtained through fixed annual contributions of $300 million from 2029 through 2045, plus an additional $3.9 billion in contingent shareholder contributions payable in annual installments of $780 million. SDG&E’s proportionate share of the aggregate shareholder contribution amount through 2045 is expected to be $387 million, comprising (i) $219.3 million of fixed contributions of $12.9 million annually for 17 years, and (ii) $167.7 million of contingent contributions of $33.5 million annually for five years.
The 2025 Wildfire Legislation establishes a multi-stakeholder task force, coordinated by the Wildfire Fund’s administrator, to prepare and submit to the California legislature and Governor of California on or before April 1, 2026, a report that evaluates and sets forth recommendations on new models to complement or replace the Wildfire Fund. If the Wildfire Fund and the Continuation Account, if it becomes operative, are materially diminished, exhausted or terminated, SDG&E would lose the protection afforded by these funds, and as a consequence, a fire in any California electric IOUs’ 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.
FERC Rate Matters
SDG&E files separately with the FERC for its authorized transmission revenue requirement and ROE on FERC-regulated electric transmission operations and assets.
TO5 Settlement. SDG&E’s authorized TO5 settlement provided for an ROE of 10.60%, consisting of a base ROE of 10.10% plus the California ISO adder. In December 2024, the FERC issued an order, which SDG&E has appealed, finding that SDG&E is not eligible for the California ISO adder and that the TO5 adder refund provision had been triggered, requiring SDG&E to refund customers the California ISO adder retroactively from June 1, 2019.
TO6 Filing. In October 2024, SDG&E submitted its TO6 filing to the FERC and requested it to be effective January 1, 2025. SDG&E’s TO6 filing proposes, among other items, an increase to SDG&E’s currently authorized base ROE from 10.10% to 11.75% plus the California ISO adder, for a total ROE of 12.25%. In December 2024, the FERC accepted SDG&E’s TO6 filing, subject to refund; suspended the effective date to June 1, 2025; established hearing and settlement judge procedures; and disallowed the inclusion of the California ISO adder, the last of which SDG&E has appealed.
Off-Balance Sheet Arrangements
SDG&E has entered into PPAs and tolling agreements that are variable interests in unconsolidated entities. We discuss variable interests in Note 1 of the Notes to Condensed Consolidated Financial Statements.
SoCalGas
Catastrophic Events Cost Recovery
In July 2025, the CPUC issued an FD that authorizes partial recovery of costs recorded in SoCalGas’ Catastrophic Event Memorandum Account. The FD authorizes the recovery of $19 million out of the requested $55 million, denying recovery of COVID-19 costs included in the Catastrophic Event Memorandum Account. In the nine months ended September 30, 2025, SoCalGas recorded a write-off of $36 million ($25 million after tax) in disallowed costs, comprising a $29 million reduction in Utilities: Natural Gas Revenues and a $7 million reduction in regulatory interest in Other (Expense) Income, Net, on Sempra’s and SoCalGas’ Condensed Consolidated Statements of Operations. SoCalGas has filed a request with the CPUC for a rehearing of the FD. SoCalGas expects to receive a post-rehearing FD in the first half of 2026.
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LA Fires
The LA Fires burned in SoCalGas’ service territory. The California Department of Forestry and Fire Protection estimated that the Palisades and Eaton fires destroyed approximately 16,200 structures and damaged approximately 2,000 structures. SoCalGas’ infrastructure in the fire-affected areas that is underground, which constitutes most of its infrastructure in these areas, remains undamaged by the fires and we believe safe to continue serving customers as they return to their homes and businesses. To date, natural gas service has been restored to almost 16,000 customers in the Eaton and Palisades fire areas, and crews will continue that work as customers return to their properties.
Aliso Canyon Natural Gas Storage Facility
Litigation. From October 23, 2015 through February 11, 2016, SoCalGas experienced the Leak, which we discuss in Note 13 of the Notes to Condensed Consolidated Financial Statements in this report and in “Part I – Item 1A. Risk Factors” in the Annual Report. As of October 31, 2025, there are three outstanding plaintiffs who have not agreed to a settlement in principle.
Operations and Reliability. Natural gas withdrawn from storage is important to help maintain service reliability during peak demand periods, including consumer heating needs in the winter and peak electric generation needs in the summer. The Aliso Canyon natural gas storage facility is the largest SoCalGas storage facility and an important component of SoCalGas’ delivery system. Subject to future CPUC biennial reviews and potential additional proceedings, the CPUC determined that the Aliso Canyon natural gas storage facility is currently necessary for natural gas and electric reliability and affordable rates and authorized it to continue operating at a maximum working natural gas storage level of 68.6 bcf.
Labor Relations
Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council. The collective bargaining agreement for these employees covering wages, hours, working conditions, and medical and other benefit plans was due to expire on September 30, 2024, but was extended by mutual agreement while SoCalGas and the unions continued negotiations. A new collective bargaining agreement was ratified on March 31, 2025 and is scheduled to expire on September 30, 2028.
Sempra Texas Utilities
Oncor relies on external financing as a significant source of liquidity for its capital requirements. In the event that Oncor fails to meet its capital requirements, 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.
Oncor
2025 Comprehensive Base Rate Review. In June 2025, Oncor filed a request for a comprehensive base rate review with the PUCT and the 210 cities in its service territory that have retained original jurisdiction over rates. The base rate review test year is based on calendar year 2024 results with certain adjustments. The base rate review includes a request for an average increase over test year adjusted annualized revenue of approximately 13%, and if approved as requested, would result in an aggregate annualized revenue increase of approximately $834 million over current adjusted rates. The base rate review also requests a revised regulatory capital structure ratio of 55% debt to 45% equity, an authorized ROE of 10.55%, and a 4.94% authorized cost of debt. Oncor’s current authorized regulatory capital structure ratio is 57.5% debt to 42.5% equity, a 9.7% authorized ROE and 4.39% authorized cost of debt.
PUCT rules permit the filing of a request for interim rates while a base rate proceeding is pending. In July 2025, Oncor filed a request for an interim rate review. In September 2025, the administrative law judge approved a settlement agreement among the parties relating to interim rates. That order provides that, if the base rate proceeding is still pending as of January 1, 2026 and not otherwise subject to a PUCT-approved settlement of the base proceeding, Oncor’s existing rates will be deemed interim rates subject to refund or surcharge back to January 1, 2026, based on the final rates approved by the PUCT in the base rate proceeding.
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2023 Comprehensive Base Rate Review Order. The PUCT issued a final order in Oncor’s comprehensive base rate proceeding in April 2023, and rates implementing that order went into effect on May 1, 2023. In June 2023, the PUCT issued an order on rehearing in response to the motions for rehearing filed by Oncor and certain intervening parties in the proceeding. The order on rehearing made certain technical and typographical corrections to the final order but otherwise affirmed the material provisions of the final order and did not require modification of the rates that went into effect on May 1, 2023. In September 2023, Oncor filed an appeal in Travis County District Court seeking judicial review of certain rate base disallowances and related expense effects of those disallowances in the PUCT’s order on rehearing. In February 2024, the court dismissed the appeal for lack of jurisdiction. In March 2024, Oncor appealed the court’s dismissal with the Fifteenth Court of Appeals in Texas. On August 14, 2025, the court issued its opinion in favor of the PUCT and dismissed Oncor’s appeal. Oncor has elected not to pursue a further appeal.
Unified Tracker Mechanism. In June 2025, Texas House Bill 5247 was signed into law and became effective. The bill establishes what is known as the UTM, which creates an alternative method, available through 2035, for qualifying electric utilities to apply for interim rate adjustments once annually using a comprehensive regulatory filing for cost recovery of certain transmission and distribution capital expenditures.
A qualifying utility electing to use the UTM is permitted to defer all or a portion of the costs associated with its eligible transmission and distribution capital investments placed into service during the period covered by the UTM, including depreciation expense and carrying costs, as a regulatory asset. Texas House Bill 5247 provides that the PUCT must review a UTM filing within 120 days, and if a final order is not issued by the PUCT within 165 days after the UTM filing is submitted, the utility can place the requested rates into effect on a temporary basis and refund or credit against future customer bills any difference between such temporary rates and the final approved rates.
Oncor expects to make its first comprehensive UTM filing in the first half of 2026 with a view toward recovering the costs associated with eligible transmission and distribution investments that were placed into service after December 31, 2024 and that are not currently reflected in rates. Since the June 2025 effective date of the bill, Oncor has recognized revenues and corresponding regulatory assets for recoverable costs related to UTM-eligible transmission and distribution capital investments that were placed into service from January 1, 2025 through September 30, 2025, including depreciation expense, carrying costs on unrecovered balances and related taxes. Oncor expects to continue recognizing revenues and corresponding regulatory assets as UTM-eligible transmission and distribution capital investments are placed into service.
Sharyland Utilities
On May 1, 2025, Sharyland Utilities filed its 2025 rate case using a test year based on calendar year 2024 with certain adjustments. Sharyland Utilities is seeking a revenue requirement of $55 million, which is an approximately 14% increase over adjusted test-year revenues. Sharyland Utilities is also requesting a rate of return of 7.32%, which is based on a proposed capital structure ratio of 55% debt to 45% equity; a proposed ROE of 10.75%; and a proposed long-term cost of debt of 4.52%.
On September 16, 2025, Sharyland Utilities, the PUCT Staff and Texas Industrial Energy Consumers reached a unanimous settlement. Under the settlement, Sharyland Utilities’ total revenue requirement would be set at $53 million, with a capital structure ratio of 59% debt to 41% equity; an ROE of 9.60%; and a long-term cost of debt of 4.52%. Although the administrative law judge had prepared a draft order for the Commission’s consideration, the PUCT typically considers cases directly when they are settled unanimously, making a formal recommendation from the judge on the merits unnecessary. Sharyland Utilities continues to expect a final order in the fourth quarter of 2025, with rates, if approved, going into effect in December 2025.
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 Condensed Consolidated Financial Statements.
Sempra Infrastructure
Sempra Infrastructure expects to fund capital expenditures, investments and operations in part with available funds, including existing credit facilities, and cash flows from operations from 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 NCI owners, bank financing, issuances of debt, project financing, partnering in JVs and asset sales.
In the nine months ended September 30, 2025 and 2024, Sempra Infrastructure distributed $131 million and $235 million, respectively, to its NCI owners, and NCI owners contributed $137 million and $1,121 million, respectively, to Sempra Infrastructure.
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Sempra Infrastructure is in various stages of development or construction of natural gas liquefaction projects, pipeline and terminal projects, and renewable power generation and sequestration projects, which we describe below. The successful development and/or construction of these projects is subject to numerous risks and uncertainties.
With respect to projects in development, these risks and uncertainties include, as applicable depending on the project, any failure to:
▪secure binding customer commitments
▪identify suitable project and equity partners
▪obtain sufficient financing
▪reach agreement with project partners or other applicable parties to proceed
▪obtain, modify, and/or maintain permits and regulatory approvals, including LNG export applications to non-FTA countries
▪negotiate, complete and maintain suitable commercial agreements, which may include EPC, tolling, equity acquisition, governance, LNG sales, gas supply and transportation contracts
▪reach a positive FID
With respect to projects under construction, these risks and uncertainties include, in addition to the risks described above as applicable to each project, construction delays, unforeseen design flaws, cost overruns and other construction-related issues.
An unfavorable outcome with respect to any of these factors could have a material adverse effect on (i) the development and construction of the applicable project, including a potential impairment of all or a substantial portion of the capital costs invested in the project to date, which could be material, and (ii) for any project that has reached a positive FID, Sempra’s results of operations, financial condition, cash flows and/or prospects. For a further discussion of these risks, see “Part I – Item 1A. Risk Factors” in the Annual Report.
The descriptions below discuss several HOAs, MOUs and other non-binding development agreements with respect to Sempra Infrastructure’s various development projects. These arrangements do not commit any party to enter into definitive agreements or otherwise participate in the applicable project, and the ultimate participation by the parties remains subject to negotiation and finalization of definitive agreements, among other factors.
SI Partners
As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, in September 2025, we entered into an agreement to sell a 45% equity interest in SI Partners to the KKR Partners for $9.99 billion, subject to adjustments. We expect the sale to close in the second or third quarter of 2026, subject to expiration of the waiting period under the Hart-Scott-Rodino Act; receipt of applicable regulatory approvals, such as antitrust approvals in Mexico and approval by the FERC; receipt of certain other third-party consents or waivers; the absence of a material adverse effect on SI Partners; the absence of specific downgrade events under certain financing arrangements; and other customary closing conditions. As a result of satisfying all applicable criteria, we classified SI Partners’ assets and liabilities as held for sale and ceased depreciation and amortization.
Subject to adjustments described in Note 6 of the Notes to Condensed Consolidated Financial Statements, the purchase price will be paid to Sempra as follows:
▪$4.65 billion in cash at closing;
▪$4.14 billion plus interest compounded quarterly at 7.5% per annum (totaling $4.72 billion with principal and accrued interest unless paid early) due December 31, 2027 under instruments backed by equity commitment letters; and
▪$1.2 billion plus interest compounded quarterly at 8.5% per annum before January 1, 2031 and 10.0% per annum thereafter (totaling $2.29 billion with principal and accrued interest unless paid early) due seven years and 91 days after closing under promissory notes.
Subject to closing, the KKR Partners will own 65% of SI Partners, Sempra will retain a 25% interest and ADIA will retain a 10% interest, and we will deconsolidate SI Partners and account for our 25% interest in SI Partners under the equity method within the existing Sempra Infrastructure segment.
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Additionally, upon closing, we expect Sempra’s ownership interests in the following LNG projects to change as follows:
OWNERSHIP INTERESTS
Pre-salePost-sale
Sempra:
Cameron LNG Phase 1 facility35.1 %12.6 %
ECA LNG Phase 1 project(1)
58.4 %20.9 %
PA LNG Phase 1 project(1)
19.6 %7.0 %
PA LNG Phase 2 project35.1 %12.5 %
(1)    SI Partners will continue to be subject to substantially the same funding obligations post-sale as it is pre-sale for cost overruns in the construction of this project.
LNG
Cameron LNG Phase 2 Project. Cameron LNG JV is developing a proposed expansion project that would add one electric drive 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 has received major permits, which have been amended to allow the use of electric drives for a one-train electric drive expansion along with other design enhancements, and FTA and non-FTA approvals associated with the potential expansion. The non-FTA approval for the proposed Cameron LNG Phase 2 project includes, among other things, a May 2026 deadline to commence commercial exports. In October 2025, we filed a request with the FERC and DOE to extend the construction deadlines associated with our construction authorization and non-FTA authorizations, respectively. Those requests seek an extension of the relevant deadlines until the first quarter of 2033.
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 a non-binding HOA for the potential development of the Cameron LNG Phase 2 project. The non-binding HOA provides a commercial framework for the proposed project, including the contemplated allocation to SI Partners of 50.2% of the fourth train production capacity and 25% of the debottlenecking capacity from the project under tolling agreements. The non-binding HOA contemplates the remaining capacity to be allocated equally to the existing Cameron LNG Phase 1 facility customers.
Entergy Louisiana, LLC, a subsidiary of Entergy Corporation, and Cameron LNG JV have an electricity service agreement (and related ancillary agreements) for the supply to Cameron LNG JV of up to 950 MW of power from new renewable sources in Louisiana.
Cameron LNG JV concluded additional value engineering work on the proposed project in December 2024, which improved the overall anticipated value of the project and enabled evaluation of another potential EPC contractor. In collaboration with our partners, we continue to evaluate the results of this work as well as the full scope of the proposed project.
Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the members, including with respect to the equity investment obligation of each member. Expansion of the Cameron LNG Phase 1 facility beyond the first three trains is also 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. An FID remains subject to, among other things, securing these consents of the members and project lenders, satisfactory conclusion on the EPC process, negotiation and finalization of definitive offtake agreements and completion of all related financing and permitting activities.
ECA LNG Phase 1 Project. 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. SI Partners owns an 83.4% interest in ECA LNG Phase 1, resulting in Sempra Infrastructure holding a 58.4% interest in the project. An affiliate of TotalEnergies SE owns the remaining 16.6% interest in the project.
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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. In September 2025, we submitted a filing with the DOE to extend the construction deadline associated with our non-FTA permits until the end of summer 2026. 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. The customers have a termination right if the ECA LNG Phase 1 project does not commence commercial operations under the SPAs by February 24, 2026, subject to certain additional conditions, for which we have requested an extension.
We have an EPC contract with TP Oil & Gas Mexico, S. De R.L. De C.V., an affiliate of Technip Energies N.V., to construct the ECA LNG Phase 1 project. We estimate the total price of the EPC contract to be approximately $1.6 billion, with capital expenditures approximating $2.5 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the ECA LNG Phase 1 project to produce LNG cargoes for sale in the spring of 2026 and sales under the long-term SPAs to begin shortly after substantial completion when the facility commences commercial operations, which is targeted in the summer of 2026. Reaching substantial completion under the EPC contract is subject to various milestones, including achieving certain performance tests and functionality.
ECA LNG Phase 1 has a loan agreement with a syndicate of external lenders that was set to mature in December 2025 and was originally for an aggregate principal amount of up to $1.3 billion. As we discuss in Note 7 of the Notes to Condensed Consolidated Financial Statements, in July 2025, ECA LNG Phase 1 amended the loan agreement, which included extending the maturity date to December 2027 and increasing the aggregate borrowing capacity to $1.5 billion. At September 30, 2025 and December 31, 2024, $1.2 billion and $1.1 billion, respectively, of borrowings were outstanding under the loan agreement, with a weighted-average interest rate of 6.39% and 7.29%, respectively. Proceeds from the loan are being used to finance the cost of construction of the ECA LNG Phase 1 project.
With respect to the ECA LNG Phase 1 and Phase 2 projects, recent and proposed changes to the Mexican Constitution and certain laws in Mexico and an unfavorable resolution of a land dispute and permit challenges, in each case that we discuss in Note 13 of the Notes to Condensed Consolidated Financial Statements, could have a material adverse effect on the development and construction of these projects.
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. The ECA Regas Facility currently has firm storage service agreements and nitrogen injection service agreements with Shell México Gas Natural, S. de R.L. de C.V. and SEFE Marketing & Trading México S. de R.L. de C.V. that expire in May 2028 and December 2025, respectively. We expect that future construction of the proposed ECA LNG Phase 2 project would conflict with the current operations at the ECA Regas Facility to the extent those agreements have not expired or have not been earlier terminated at the time of such construction.
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. In October 2025, we submitted a request with the DOE seeking clarification with the agency that the construction deadline associated with the project will be December 2029, as we requested in our prior application. Alternatively, we requested that the agency extend the deadline to that date for good cause shown.
We have non-binding MOUs and/or HOAs with Mitsui & Co., Ltd., an affiliate of 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.
PA LNG Phase 1 Project. Sempra Infrastructure is constructing a natural gas liquefaction project on a greenfield site that it owns in the vicinity of Port Arthur, Texas, located along the Sabine-Neches waterway. The PA LNG Phase 1 project 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. At September 30, 2025, SI Partners, KKR Denali and an affiliate of ConocoPhillips own a 28%, 42% and 30% interest, respectively, in the PA LNG Phase 1 project. Sempra Infrastructure holds a 19.6% interest in the project.
Sempra Infrastructure has received authorizations from the DOE that permit the LNG to be produced from the PA LNG Phase 1 project to be exported to all current and future FTA and non-FTA countries. In April 2019, the FERC approved the siting, construction and operation of the PA LNG Phase 1 project. Port Arthur LNG I has received authorization from the FERC, subsequently extended in October 2025 to include the PA LNG Phase 2 Project, to increase its work force and implement a 24-hours-per-day construction schedule to further enhance construction efficiency while reducing temporal impacts to the community and environment in the vicinity of the project. The authorization provides the EPC contractor with more optionality to meet or exceed the project’s construction schedule.
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The PA LNG Phase 1 project holds two Clean Air Act, Prevention of Significant Deterioration permits issued by the TCEQ, which we refer to as the “2016 Permit” and the “2022 Permit.” The 2022 Permit also governs emissions for the PA LNG Phase 2 project. In November 2023, a panel of the U.S. Court of Appeals for the Fifth Circuit issued a decision to vacate and remand the 2022 Permit to the TCEQ for additional explanation of the agency’s permit decision. In February 2024, the court withdrew its opinion and referred the case to the Supreme Court of Texas to resolve the question of the appropriate standard to be applied by the TCEQ. In February 2025, the Supreme Court of Texas adopted Port Arthur LNG I’s interpretation of the standard. In August 2025, the U.S. Court of Appeals for the Fifth Circuit applied the standard adopted by the Supreme Court of Texas and denied the petitioner’s argument under the case, resulting in the continued effectiveness of the 2022 Permit. The petitioners have until November 10, 2025 to file a petition for writ of certiorari with the U.S. Supreme Court; however, the Supreme Court does not have to grant review. The 2022 Permit is effective during the pending litigation. The 2016 Permit was not the subject of, and is unaffected by, the pending litigation of the 2022 Permit. Construction of the PA LNG Phase 1 project is proceeding uninterrupted under existing permits, and we do not currently anticipate the pending litigation to materially impact the PA LNG Phase 1 project cost, schedule or expected commercial operations at this stage.
Sempra Infrastructure has definitive SPAs for LNG offtake from the PA LNG Phase 1 project with:
▪an affiliate of ConocoPhillips for a 20-year term for 5 Mtpa of LNG, as well as a natural gas supply management agreement whereby an affiliate of ConocoPhillips will manage the feed gas supply requirements for the PA LNG Phase 1 project.
▪RWE Supply & Trading GmbH, a subsidiary of RWE AG, for a 15-year term for 2.25 Mtpa of LNG.
▪INEOS Energy Trading Limited, a subsidiary of INEOS Limited, for a 20-year term for approximately 1.4 Mtpa of LNG.
▪Polski Koncern Naftowy Orlen S.A. 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.
We have an EPC contract with Bechtel to construct the PA LNG Phase 1 project, which has an estimated price of approximately $10.8 billion, including change orders contemplated in project contingency. Estimated capital expenditures for the PA LNG Phase 1 project remain unchanged at approximately $13 billion including capitalized interest at the project level and project contingency. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ materially from our estimates, including as a result of the imposition of tariffs. We expect the first and second trains of the PA LNG Phase 1 project to commence commercial operations in 2027 and 2028, respectively.
As we discuss in Note 13 of the Notes to Condensed Consolidated Financial Statements, in April 2025, an incident occurred at the site of the PA LNG Phase 1 project that resulted in the deaths of three Bechtel employees and injuries to two Bechtel employees. OSHA opened inspections with respect to Bechtel and Sempra Infrastructure but has released the site. Bechtel is continuing construction of the PA LNG Phase 1 project while the cause of the incident remains under investigation. As of October 31, 2025, there are two pending lawsuits filed by 17 plaintiffs. Bechtel is providing indemnity pursuant to the terms of Port Arthur LNG I’s EPC contract.
As we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements, SI Partners and ConocoPhillips have provided guarantees relating to their respective affiliate’s commitment to make its pro rata equity share of capital contributions to fund 110% of the development budget of the PA LNG Phase 1 project, in an aggregate amount of up to $9.0 billion. SI Partners’ guarantee covers 70% of this amount plus enforcement costs of its guarantee. As of September 30, 2025, an aggregate amount of $2.7 billion has been paid by SI Partners’ subsidiary in satisfaction of its commitment to fund its portion of the development budget of the PA LNG Phase 1 project.
Port Arthur LNG I has a seven-year term loan facility for an aggregate principal amount of approximately $6.8 billion and an initial working capital facility for up to $200 million, each of which matures in March 2030. At September 30, 2025, $2.2 billion of borrowings were outstanding under the term loan facility agreement. Proceeds from the loan are being used to finance the cost of construction of the PA LNG Phase 1 project.
In January 2025, Port Arthur LNG I issued senior secured notes for an aggregate principal amount of $750 million and received proceeds of $742 million (net of debt issuance costs of $8 million). In April 2025, Port Arthur LNG I issued senior secured notes for an aggregate principal amount of $250 million and received proceeds of $248 million (net of debt issuance costs of $2 million). The notes mature in December 2042. The net proceeds were used to repay borrowings and accrued interest under the existing Port Arthur LNG I term loan facility.
PA LNG Phase 2 Project. Since reaching a positive FID in September 2025, Sempra Infrastructure has commenced construction of a second phase of the Port Arthur natural gas liquefaction project that we expect will be a similar size to the PA LNG Phase 1 project. The PA LNG Phase 2 project will consist of two liquefaction trains, one LNG storage tank, and associated facilities with a nameplate capacity of approximately 13 Mtpa.
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Sempra Infrastructure has received authorizations from the DOE that permit the export of LNG from the PA LNG Phase 2 project to all current and future FTA and non-FTA countries. In September 2023, the FERC approved the siting, construction and operation of the PA LNG Phase 2 project. In September 2025, the FERC approved the start of site preparation work.
As we discuss above, a U.S. federal court previously issued and subsequently withdrew a decision that would have vacated and remanded the 2022 Permit authorizing emissions from the PA LNG Phase 1 and Phase 2 projects to the TCEQ for additional explanation of the agency’s permit decision. The U.S. Court of Appeals for the Fifth Circuit applied the standard adopted by the Supreme Court of Texas and denied the petitioner’s argument under the case, resulting in the continued effectiveness of the 2022 Permit. The ruling is subject to further appeal before it becomes final. The 2022 Permit is effective during the pending litigation.
Sempra Infrastructure has entered into a non-binding HOA for a 20-year SPA with Aramco International Gas Holding Co B.V. (Aramco) for 5 Mtpa of LNG offtake from the PA LNG Phase 2 project. The HOA further contemplates Aramco’s 25% participation in the project-level equity of the PA LNG Phase 2 project.
Sempra Infrastructure has definitive SPAs for LNG offtake from the PA LNG Phase 2 project with:
▪ConocoPhillips for a 20-year term for 4 Mtpa of LNG on a free-on-board basis
▪EQT Corporation for a 20-year term for 2 Mtpa of LNG on a free-on-board basis
▪JERA Co. Inc. for a 20-year term for 1.5 Mtpa of LNG on a free-on-board basis
In addition, SI Partners has a definitive SPA with the project for a 20-year term for 2.5 Mtpa of LNG and has entered into offtake agreements for excess quantities of LNG, which includes an offtake agreement for a 30-year term to the extent of incremental amounts produced above 10 Mtpa up to an additional 0.75 Mtpa.
We have an EPC contract with Bechtel to construct the PA LNG Phase 2 project. In September 2025, we issued a full notice to proceed under the EPC contract, which has an estimated price of approximately $9.0 billion, including change orders contemplated in project contingency. The total currently estimated capital expenditures for the project are approximately $14 billion, including, among other items, project contingency and a $1.9 billion true-up payment to the PA LNG Phase 1 project to acquire a 50% interest in the shared common facilities. The actual cost of the EPC contract and the actual amount of these capital expenditures may differ substantially from our estimates. We expect the third and fourth trains of the Port Arthur LNG liquefaction project to commence commercial operations in 2030 and 2031, respectively.
To secure gas supply for the PA LNG Phase 2 project, Sempra Infrastructure entered into a natural gas transportation agreement with a third-party pipeline developer. The transportation capacity commitment is subject to completion of pipeline construction by a third-party developer that is expected to occur by early 2029. Sempra Infrastructure holds a contractual option to acquire the third party’s interest in the pipeline if certain construction milestones are not met, which would release Sempra Infrastructure from the associated capacity commitment. In September 2025, we provided certain equity commitments related to the Mustang Express Pipeline but, in October 2025, we transferred the full amount of these commitments to third parties.
As we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements, in September 2025, PA2 JVCo issued 49.9% of its equity interests to Blackstone for $3.4 billion in cash at closing and a commitment to fund an additional $3.6 billion of capital contributions on a pre-determined funding schedule whereby Blackstone’s capital contributions are scheduled prior to SI Partners capital contributions. SI Partners holds the remaining 50.1% of equity interests in PA2 JVCo, and has committed to fund up to $7.8 billion to PA2 JVCo to support its share of the budgeted PA LNG Phase 2 project construction costs. SI Partners will continue to consolidate PA2 JVCo and direct the activities related to the construction and future operation and maintenance of the PA LNG Phase 2 project. Blackstone’s equity interest is subject to redemption and exit rights that are outside the control of SI Partners and Blackstone. As a result, we account for Blackstone’s NCI as being contingently redeemable, which is presented as mezzanine equity in our Condensed Consolidated Balance Sheet.
Vista Pacifico LNG Liquefaction Project. Sempra Infrastructure is developing the Vista Pacifico LNG project, a mid-scale natural gas liquefaction export facility proposed to be located in the vicinity of the Port of Topolobampo in Sinaloa, Mexico. In June 2024, we extended the non-binding development agreement with the CFE through December 2025. We continue to progress with the CFE on the negotiation of definitive agreements, including a natural gas supply agreement. The proposed LNG export terminal would be supplied with U.S. natural gas and would use excess 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 and non-FTA countries.
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In March 2022, TotalEnergies SE and Sempra Infrastructure entered into a non-binding 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.
Asset and Supply Optimization. As we discuss in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Annual Report, Sempra Infrastructure enters into hedging transactions to help mitigate commodity price risk and optimize the value of its LNG, natural gas pipelines and storage, and power-generating assets. 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, which may be material, as the economic offset of these derivatives may not be recorded at fair value.
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 Condensed Consolidated Financial Statements.
In February 2025, SI Partners entered into a credit support agreement, which constitutes a guarantee, for the benefit of a third-party financial institution with a maximum exposure to loss of $85 million. The guarantee will terminate in May 2026. We discuss this guarantee in Note 13 of the Notes to Condensed 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 13 of the Notes to Condensed 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, 9 and 13 of the Notes to Condensed Consolidated Financial Statements.
Energy Networks
Ecogas. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, in June 2025, management committed to a formal plan to market and sell Ecogas, a natural gas regulated distribution utility that operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. We expect to complete the sale in the second or third quarter of 2026. As a result of satisfying all applicable criteria, we classified Ecogas’ assets and liabilities as held for sale and ceased depreciation and amortization. Successful completion of a sale and the timing of such sale is subject to a number of risks and uncertainties, including reaching agreement on acceptable pricing and other terms, securing required regulatory and other approvals, finalizing definitive contracts and other factors and considerations.
Sonora Pipeline. Sempra Infrastructure’s Sonora natural gas pipeline consists of two pipeline segments, the Sasabe-Puerto Libertad-Guaymas segment and the Guaymas-El Oro segment. Each segment has its own service agreement with the CFE. Following the start of commercial operations of the Guaymas-El Oro segment, Sempra Infrastructure reported damage to the pipeline in the Yaqui territory that has made that section inoperable since August 2017 because it was not able to be repaired due to legal challenges, which were resolved in March 2023, by some members of the Yaqui tribe.
In September 2019, Sempra Infrastructure and the CFE reached an agreement to modify the tariff structure and extend the term of the contract by 10 years. 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.
Sempra Infrastructure and the CFE have agreed to an amendment to their transportation services agreement and to re-route the portion of the pipeline that is in the Yaqui territory, whereby the CFE would pay for the re-routing with a new tariff. This amendment will terminate if certain conditions are not met, and Sempra Infrastructure retains the right to terminate the transportation services agreement and seek to recover its reasonable and documented costs and lost profit. Sempra Infrastructure continues to acquire and pursue the necessary rights-of-way and permits for the portion of the pipeline that needs to be re-routed.
The Guaymas-El Oro segment of the Sonora pipeline currently constitutes a Sole Risk Project under the terms of the SI Partners limited partnership agreement, which means that Sempra Infrastructure holds a 100% interest in the project. Sole Risk Projects are separated from other SI Partners projects and are conducted at Sempra’s sole cost, expense and liability and Sempra Infrastructure receives, through the acquisition of Sole Risk Interests, any economic and other benefits from such projects. The Guaymas-El Oro segment will continue to be owned by and a Sole Risk Project of Sempra after closing the sale of a portion of our equity interest in SI Partners, which we discuss in Note 6.
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At September 30, 2025, Sempra Infrastructure has $391 million of PP&E, net, related to the Guaymas-El Oro segment of the Sonora pipeline, which could be subject to impairment if, among other things, Sempra Infrastructure is unable to re-route a portion of the pipeline 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.
Port Arthur Pipeline Louisiana Connector. Sempra Infrastructure is constructing the Port Arthur Pipeline Louisiana Connector, a 72-mile pipeline connecting the PA LNG Phase 1 project to Gillis, Louisiana. In April 2019, the FERC approved the siting, construction and operation of the Port Arthur Pipeline Louisiana Connector, which will be used to supply feed gas to the PA LNG Phase 1 project. Sempra Infrastructure received FERC approval to implement construction process enhancements and minor modifications to several discrete sections of the Port Arthur Pipeline Louisiana Connector. These modifications are intended to decrease environmental impacts, accommodate landowner routing requests and enhance construction procedures. We expect the Port Arthur Pipeline Louisiana Connector to be ready for service ahead of the PA LNG Phase 1 project’s gas requirements. We estimate the capital expenditures for the project will be approximately $1 billion, including capitalized interest at the project level and project contingency. The actual amount of capital expenditures may differ substantially from our estimates.
Louisiana Storage. Sempra Infrastructure is constructing Louisiana Storage, a 12.5-Bcf salt dome natural gas storage facility to support the PA LNG Phase 1 project. The construction includes an 11-mile pipeline that will connect to the Port Arthur Pipeline Louisiana Connector. In September 2022, the FERC approved the development of the project. We expect Louisiana Storage to be ready for service in time to support the needs of the PA LNG Phase 1 project. We estimate the capital expenditures for the project will be approximately $400 million, including capitalized interest at the project level and project contingency. The actual amount of capital expenditures may differ substantially from our estimates.
Low Carbon Solutions
Cimarrón Wind. Sempra Infrastructure has reached a positive FID to construct the Cimarrón Wind project, an approximately 320-MW wind generation facility in Baja California, Mexico. Sempra Infrastructure has a 20-year PPA with Silicon Valley Power for the long-term supply of renewable energy to the City of Santa Clara, California. Cimarrón Wind will utilize one of Sempra Infrastructure’s existing cross-border high voltage transmission lines to interconnect and deliver clean energy to the East County substation in San Diego County. We estimate the capital expenditures for the project will be approximately $550 million, including capitalized interest at the project level and project contingency. The actual amount of capital expenditures may differ substantially from our estimates. The Cimarrón Wind project began generating energy in October 2025 and we expect commercial operations to commence in the first half of 2026.
Hackberry Carbon Sequestration Project. Sempra Infrastructure is developing the potential Hackberry Carbon Sequestration project near Hackberry, Louisiana, together with TotalEnergies SE, Mitsui & Co., Ltd. and Mitsubishi Corporation. This proposed project is designed to permanently sequester carbon dioxide from the Cameron LNG Phase 1 facility, the proposed Cameron LNG Phase 2 project and potentially other sources. In April 2025, the Louisiana Department of Energy and Natural Resources (LDENR) issued a draft Class VI carbon injection well construction permit and held the required public hearing. In September 2025, LDENR issued the final permit to construct a Class VI carbon injection well, subject to a 60-day appeal process.
Legal and Regulatory Matters
See Note 13 of the Notes to Condensed Consolidated Financial Statements in this report and “Part I – Item 1A. Risk Factors” in the Annual Report for discussions of the following legal and regulatory matters affecting our operations in Mexico and risks associated with Mexican laws, policies and government influence:
Energía Costa Azul
▪Land Disputes
▪Environmental and Social Impact Permits
One or more unfavorable conclusions 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.
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Regulatory and Other Actions by the Mexican Government
In 2021, the Mexican government amended the LIE and LH to empower Mexican regulators to, among other things, revoke or suspend permits under certain circumstances. In 2024, the Mexican government adopted changes to the Mexican Constitution to reinforce state control over strategic sectors by granting a central role to government entities like the CFE and PEMEX, which have been converted from for-profit state-owned enterprises into public state-owned enterprises. Following these constitutional reforms, in March 2025, the Mexican government adopted energy-related laws (2025 Energy Laws), including the ESL, which repealed the LIE, and the HSL, which repealed the LH. The 2025 Energy Laws increase the government’s control and participation in the energy sector and may create novel challenges for infrastructure development and operations. Like the LIE and LH, the ESL and HSL give Mexican authorities broad discretion to revoke or suspend permits under certain circumstances. In October 2025, the Mexican government enacted new regulations regarding the ESL and HSL, which provide further detail on the legal and regulatory framework of the energy sector. These new regulations provide state-owned companies preferential treatment regarding open access, increase oversight by regulators and obligations for private companies and reduce the maximum term of certain permits for new projects. For the power sector, the new regulations provide for state prevalence and additional requirements for private projects, increase oversight by regulators and sanctions and establish that self-supply permits remain valid and can migrate voluntarily to the wholesale electricity market.
Although the new laws, regulations, and certain general administrative provisions in the energy sector have been published, the extent of the impact of the 2025 Energy Laws is still uncertain. These laws and future implementation of existing and any new regulations could adversely affect Sempra Infrastructure’s ability to operate its existing assets at their current levels, result in increased costs to Sempra Infrastructure and its customers, adversely impact Sempra Infrastructure’s ability to develop new projects in Mexico, result in decreased revenues and/or cash flows, and negatively impact Sempra Infrastructure’s ability to recover the carrying values of its investments in Mexico, any of which could have a material adverse impact on Sempra’s business, results of operations, financial condition, cash flow and/or prospects.
SOURCES AND USES OF CASH
The following tables include only significant changes in cash flow activities for each of the Registrants.
CASH FLOWS FROM OPERATING ACTIVITIES
(Dollars in millions)
Nine months ended September 30,SempraSDG&ESoCalGas
2025$3,376 $1,343 $1,426 
20243,542 1,443 1,370 
Change$(166)$(100)$56 
Change in regulatory accounts, current and noncurrent$(534)$(215)$(319)
Change in accounts receivable(331)(133)(58)
Increase in income taxes payable, net(92)
Change in net margin posted, current and noncurrent(84)
Change in inventories(32)
Change in GHG obligations, current and noncurrent23 42 
Higher accruals in interest payable50 17 
Customer’s early termination of firm transportation agreements
52 
Higher net income, adjusted for noncash items included in earnings87 68 71 
Change in accrued franchise fees92 76 16 
Change in GHG allowances, current and noncurrent105 86 41 
Change in fixed-price contracts and other derivatives, current and noncurrent134 133 
Higher distributions from Oncor Holdings158 
Change in accounts payable183 28 130 
Other(9)5  
$(166)$(100)$56 
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CASH FLOWS FROM INVESTING ACTIVITIES
(Dollars in millions)
Nine months ended September 30,Sempra SDG&ESoCalGas
2025$(8,605)$(1,762)$(1,523)
2024(6,296)(1,793)(1,491)
Change$(2,309)$31 $(32)
(Increase) decrease in capital expenditures$(1,436)$27 $(32)
Higher contributions to Oncor Holdings(912)
Other39 4  
$(2,309)$31 $(32)
CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
Nine months ended September 30,SempraSDG&ESoCalGas
2025$6,661 $419 $85 
20243,066 315 121 
Change$3,595 $104 $(36)
Contributions from contingently redeemable noncontrolling interest, net of transaction costs$3,212 
Higher issuances of long-term debt1,864 $254 
Change in borrowings and repayments of short-term debt, net759 (774)$1,020 
Higher (lower) issuances of short-term debt with maturities greater than 90 days591 (500)
Proceeds from investor equity subscription106 
Lower distributions to NCI104 
(Higher) lower common dividends paid(74)225 
Higher payments on short-term debt with maturities greater than 90 days(485)(700)
Lower contributions from NCI(984)
(Higher) lower payments on long-term debt and finance leases(1,441)400 148 
Other(57)(1)(4)
$3,595 $104 $(36)
Capital Expenditures for PP&E and Investments
CAPITAL EXPENDITURES FOR PP&E AND INVESTMENTS
(Dollars in millions)
Nine months ended September 30,
 20252024
Sempra:
Sempra California(1)
$3,334 $3,329 
Sempra Texas Utilities1,490 578 
Sempra Infrastructure3,865 2,443 
Segment totals8,689 6,350 
Parent and other4 3 
Total Sempra$8,693 $6,353 
(1)    Includes capital expenditures for PP&E of $1,811 and $1,838 at SDG&E and $1,523 and $1,491 at SoCalGas for 2025 and 2024, respectively.
We expect capital expenditures for PP&E and investments in 2025 to total $13.3 billion, which is an increase from the $12.5 billion projected in “Part II – Item 7. MD&A – Capital Resources and Liquidity” in the Annual Report. The increase is primarily attributable to capital expenditures for the PA LNG Phase 2 project, which reached a positive FID in September 2025. When (i) including Sempra’s proportionate ownership interest in expected capital expenditures for PP&E at unconsolidated equity method investees while excluding Sempra’s expected capital contributions to those unconsolidated equity method investees and (ii) excluding NCI’s proportionate ownership interest in expected capital expenditures for PP&E at Sempra and at unconsolidated equity method investees, we expect capital expenditures for PP&E in 2025 to total $12.9 billion.
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Oncor expects to announce a new five-year base capital plan for the years 2026 through 2030 in the first half of 2026, following the conclusion of its base rate review, and currently expects that capital expenditure plan to be at least 30% higher than Oncor’s 2025 through 2029 base capital plan of $36 billion. Oncor also anticipates significant potential capital expenditure opportunities incremental to the 2026 through 2030 base capital plan. Changes in Oncor’s capital expenditures plan could result in corresponding changes to our capital expenditures plan based on our ownership interest in Oncor.
Our level of capital expenditures for PP&E and investments will depend on, among other things, the cost and availability of financing, regulatory approvals, changes in tax law and business opportunities providing desirable rates of return, among various other factors described in this MD&A and in “Part I – Item 1A. Risk Factors” in the Annual Report. We aim to finance our capital expenditures for PP&E and investments 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.
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 in “Part II – Item 7. MD&A” in the Annual Report.
NEW ACCOUNTING STANDARDS
We discuss any 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 Condensed Consolidated Financial Statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We provide disclosure regarding derivative activity in Note 8 of the Notes to Condensed Consolidated Financial Statements. We discuss our market risk and risk policies in detail in “Part II – Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in the Annual Report.
COMMODITY PRICE RISK
Sempra Infrastructure is exposed to commodity price risk indirectly through its LNG, natural gas pipelines and storage, and power-generating assets. In the first nine months of 2025, 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 $12 million at September 30, 2025 compared to $13 million at December 31, 2024.
The one-day value at risk for SDG&E’s and SoCalGas’ commodity positions were $1 million and $6 million, respectively, at September 30, 2025 compared to $2 million for each at December 31, 2024.
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INTEREST RATE RISK
The table below shows the nominal amount of our debt:
NOMINAL AMOUNT OF DEBT(1)
(Dollars in millions)
 September 30, 2025December 31, 2024
 SempraSDG&ESoCalGasSempraSDG&ESoCalGas
Short-term:
Sempra California$438 $27 $411 $1,454 $417 $1,037 
Other(2)
2,293 — — 562 — — 
Long-term:
Sempra California fixed-rate$17,909 $9,800 $8,109 $16,309 $8,950 $7,359 
Other fixed-rate(2)
17,338 — — 15,527 — — 
Other variable-rate(2)
1,580 — — 1,063 — — 
(1)    After the effects of interest rate swaps. Before reductions for unamortized discounts and debt issuance costs and excluding finance lease obligations.
(2)     At September 30, 2025, $7,858 is classified as Liabilities Held For Sale on the Sempra Condensed Consolidated Balance Sheet, which consists of $897 of short-term debt, $5,381 of long-term fixed-rate debt, and $1,580 of long-term variable-rate debt.

An interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings attributable to common shares (but disregarding capitalized interest and impacts on equity earnings from debt at our equity method investees) that would result from a hypothetical change in market interest rates. Earnings attributable to common shares 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 September 30, 2025 increased or decreased by 10%, the change in earnings attributable to common shares over the 12-month period ending September 30, 2026 would be approximately $9 million. If interest rates increased or decreased by 10% on all variable-rate long-term debt at September 30, 2025, after considering the effects of interest rate swaps, the change in earnings attributable to common shares over the 12-month period ending September 30, 2026 would be approximately $4 million.
FOREIGN CURRENCY EXCHANGE RATE RISK AND INFLATION EXPOSURE
We discuss our foreign currency exchange rate risk and inflation exposure in “Part I – Item 2. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” in this report and in “Part II – Item 7. MD&A – Impact of Foreign Currency and Inflation Rates on Results of Operations” in the Annual Report. At September 30, 2025, there were no significant changes to our exposure to foreign currency exchange rate risk since December 31, 2024.
In 2024 and 2025 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, including labor and contractor related costs as well as higher insurance premiums, and does not have specific regulatory mechanisms that allow for recovery of higher non-reconcilable 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 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 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.
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ITEM 4. CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
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 September 30, 2025, 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.
INTERNAL CONTROL OVER FINANCIAL REPORTING
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.
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PART II – OTHER INFORMATION
ITEM 1. 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), including, environmental proceedings described in Item 103(c)(3) of SEC Regulation S-K except for the matters (1) described in Note 13 of the Notes to Condensed Consolidated Financial Statements in this report and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report, or (2) referred to in “Part I – Item 2. MD&A” in this report or in “Part I – Item 1A. Risk Factors” or “Part II – Item 7. MD&A” in the Annual Report.
ITEM 1A. RISK FACTORS
When evaluating our company and its consolidated entities and any investment in our or their securities, you should carefully consider the 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), including the factors discussed below and in “Part I – Item 2. MD&A” in this report and “Part I – Item 1A. Risk Factors” and “Part II – Item 7. MD&A” in the Annual Report. Any of the risks and other information discussed in this report or any of the risk factors discussed in “Part I – Item 1A. Risk Factors” or “Part II – Item 7. MD&A” in the Annual Report, as well as additional risks and uncertainties not currently known to us or that we currently consider immaterial, could materially adversely affect our results of operations, financial condition, cash flows, prospects and/or the trading prices of our securities or those of our consolidated entities.
We may be unable to complete or realize the anticipated benefits from our planned sales of certain of our assets and businesses as part of our capital recycling program.
As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements, in September 2025, we entered into an agreement to sell a 45% equity interest in SI Partners to the KKR Partners for $9.99 billion, subject to adjustments. We expect this sale to close in the second or third quarter of 2026, subject to expiration of the waiting period under the Hart-Scott-Rodino Act; receipt of applicable regulatory approvals, such as antitrust approvals in Mexico and approval by the FERC; receipt of other third-party consents or waivers, including from certain lenders, partners and others; the absence of a material adverse effect on SI Partners; the absence of specific downgrade events under certain financing arrangements; and other customary closing conditions. Additionally, in June 2025, management committed to a formal plan to market and sell Ecogas, a natural gas regulated distribution utility that operates in three separate distribution zones in Mexicali, Chihuahua and La Laguna-Durango, Mexico. We expect to complete the sale of Ecogas in the second or third quarter of 2026. There can be no assurance that the pending sales will be completed in a timely manner or at all. Applicable regulatory authorities and other third parties may withhold the necessary approvals, seek to block or challenge the transactions in the case of certain regulatory authorities, or impose burdensome or costly requirements as conditions to approval. If the required approvals or consents are not received, the other closing conditions are not satisfied or waived, or any of the foregoing is not achieved in a timely manner or on satisfactory terms, then we may need to incur additional costs to complete these transactions, which costs could be significant, or the transactions may be abandoned, delayed or restructured, which would prevent us from realizing the potential benefits of the transactions while still bearing the substantial costs incurred to pursue them.
Even if they close, any efficiencies and benefits we expect from these transactions might be delayed or not realized. Our expectations are based on a number of assumptions, estimates, projections and other uncertainties about, among other things, closing and post-closing payments; purchase price adjustments; transaction-related tax and accounting impacts; performance by the KKR Partners of their respective contractual obligations; transition services and employee matters; the results of operations of SI Partners after the closing of the proposed transactions; and other factors beyond our control. Moreover, the planned decrease in our ownership of SI Partners would also decrease our share of the cash flows, profits and other benefits from this business. Additionally, the KKR Partners collectively would generally have control of SI Partners, subject to certain minority consent rights so long as the minority partners maintain specified ownership thresholds. The KKR Partners may not manage SI Partners in accordance with our current expectations, which could materially adversely affect the value of our minority ownership interest.
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Any of these outcomes could materially adversely affect our results of operations, cash flows, financial condition and/or prospects.
Changing conditions in global markets, including the impact of tariffs and other trade actions, may materially and adversely affect us.
Our businesses import various materials, including steel and aluminum, and purchase foreign-sourced goods, such as electrical transformers, from domestic distributors. Sempra Infrastructure also generates a material portion of its earnings from LNG exports to customers located outside the U.S., including countries in Asia and Europe. Our ability to continue importing materials and purchasing foreign-sourced goods at competitive prices and reaching positive FIDs on LNG and other significant projects in development is subject to a number of risks, including adverse impacts on the affordability of projects in development and under construction due to the imposition of tariffs by the U.S. Administration, and adverse impacts caused by (i) legal and regulatory requirements or limitations imposed by foreign governments, including tariffs, quotas or other trade barriers, sanctions, adverse tax law changes, nationalization, currency restrictions, or import restrictions, and (ii) disruptions or delays in shipments caused by customs compliance or other actions of government agencies.
In 2018, the U.S. imposed tariffs on certain imported steel and aluminum products, as well as tariffs in various ranges on imports from China. Those tariffs remain in effect. Beginning in January 2025, the U.S. Administration has announced a number of new and increased tariffs, both threatened and imposed, including a higher total tariff rate on goods from China and numerous other tariffs on imports from all countries with only limited exclusions. The U.S. Administration has delayed the effectiveness of certain tariffs and tariff rate increases and threatened to accelerate the effectiveness of others. Additionally, the U.S. Administration has expanded the application of the 2018 steel and aluminum tariffs to countries and products that had previously been excluded, including a broad range of derivative products, increased steel and aluminum tariff rates, and imposed tariffs on certain imported copper products. These tariffs have created uncertainty in our business development efforts and for projects currently under construction, and we expect them to impact our businesses’ costs related to construction, pipeline transportation, electricity procurement and financing, among other areas, and increase costs across the LNG value chain. These impacts may result in delays, cost overruns or reduced profitability for our construction and development projects, denials or delays of recovery in rates of higher costs at our regulated utilities, or other adverse effects, any of which could be material.
We also face uncertainty in the interpretation and application of these tariffs, including with respect to customs valuation, product classification and country-of-origin determinations. Any disagreement with regulators on these matters could result in the retroactive assessment of additional tariffs with interest, the imposition of penalties, or other enforcement actions, any of which could be material.
These recent tariffs, along with other U.S. trade actions, have triggered retaliatory actions by certain affected countries, including China’s announcement of a tariff on U.S. LNG. Other foreign governments may also impose trade measures, including reciprocal tariffs, on LNG or other U.S. goods in the future. These tariffs and other trade actions could negatively impact demand for our LNG exports, which would adversely impact our LNG projects and development pipeline.
While the U.S. Administration has announced various trade deals, many such agreements are preliminary and may be subject to change. Certain of the announced deals, including the agreement with the European Union, require further governmental approvals, and certain announced deal terms, including purported commitments by the European Union and Japan to purchase more U.S. energy, may be non-binding or subject to voluntary implementation by the private sector. Any disagreement between the U.S. and other countries over the implementation of such trade deals or any failure to obtain required governmental approvals or otherwise reach a final agreement could result in prolonged uncertainty regarding the scope and duration of these trade actions by the U.S. and other countries. Such actions and any resulting economic, financial or geopolitical instability could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

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ITEM 5. OTHER INFORMATION
(a)None.
(b)None.
(c)During the last fiscal quarter, (i) each of the individuals listed below, who were at the time Sempra directors or officers, adopted a Rule 10b5-1 trading arrangement with respect to the securities of Sempra, with the material terms described below; (ii) no Sempra directors or officers terminated a Rule 10b5-1 trading arrangement or adopted or terminated a non-Rule 10b5-1 trading arrangement with respect to the securities of Sempra; and (iii) no SDG&E or SoCalGas directors or officers adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement with respect to the securities of each such Registrant. As used herein, directors and officers are as defined in Rule 16a-1(f) under the Exchange Act, a Rule 10b5-1 trading arrangement is as defined in Item 408(a) of SEC Regulation S-K, and a non-Rule 10b5-1 trading arrangement is as defined in Item 408(c) of SEC Regulation S-K. The Rule 10b5-1 trading arrangement listed below is intended to satisfy the affirmative defense of Rule 10b5-1(c) under the Exchange Act.
NON-RULE 10B5-1 TRADING ARRANGEMENTS
(In the three months ended September 30, 2025)
Name and title of the director or officerDate on which the director or officer adopted or terminated the trading arrangementDuration of the trading arrangementAggregate number of securities to be purchased or sold pursuant to the trading arrangement
Jeffrey W. Martin, Chairman, Chief Executive Officer and President
August 11, 2025
From January 2, 2026 until all shares are sold or the trading arrangement is otherwise terminated
53,111 owned shares of Sempra common stock
Karen L. Sedgwick, Executive Vice President and Chief Financial Officer
August 19, 2025
From November 24, 2025 until all shares are sold or the trading arrangement is otherwise terminated
▪7,564 owned shares of Sempra common stock
▪All shares of Sempra common stock subject to 2,446 time-based and 14,678 performance-based RSUs vesting in January and February 2026, plus the accumulated dividend equivalents related to such RSUs(1)
▪50% of the shares of Sempra common stock subject to 9,323 performance-based RSUs vesting in January and February of 2027(1)
in each case (other than with respect to the 7,564 owned shares), less shares to which Ms. Sedgwick would otherwise be entitled that are withheld to satisfy minimum statutory tax withholding requirements
Caroline A. Winn, Executive Vice President
August 13, 2025
From November 18, 2025 until all shares are sold or the trading arrangement is otherwise terminated
6,000 owned shares of Sempra common stock
(1)    Shares subject to the performance-based RSUs scheduled to vest in January and February of 2026 and 2027 generally will vest, in whole or in part, or be forfeited in early 2026 or early 2027, as applicable, based on our total shareholder return for the three-year performance period ending on January 2, 2026 or January 4, 2027, as applicable, and EPS growth (as adjusted for long-term incentive plan purposes) for the three-year performance period ending on December 31, 2025 and December 31, 2026, as applicable. The number of shares that will vest may range from 0% to 200% of the target number of shares (plus dividend equivalents) and cannot be ascertained until the performance period has ended and the Compensation and Talent Development Committee of Sempra’s board of directors has certified the results.
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ITEM 6. EXHIBITS
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), 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). All exhibits to which Sempra is a party have been named in this Exhibit Index with Sempra’s current legal name (Sempra) rather than its former legal name (Sempra Energy) regardless of the date of the exhibit.
EXHIBIT INDEX
Incorporated by Reference
Exhibit NumberExhibit DescriptionFiled or Furnished Herewith Form Exhibit or AppendixFiling Date
EXHIBIT 3 -- ARTICLES OF INCORPORATION AND BYLAWS
Sempra
3.1
Amended and Restated Articles of Incorporation of Sempra effective May 23, 2008.
10-K3.102/27/20
3.2
Certificate of Determination of Preferences of 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, Series C, of Sempra (including the form of certificate representing the 4.875% Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, Series C), filed with the Secretary of State of the State of California and effective June 11, 2020.
8-K3.106/15/20
3.3
Certificate of Amendment of Amended and Restated Articles of Incorporation of Sempra dated May 12, 2023.
8-K3.105/16/23
3.4
Bylaws of Sempra (as amended through May 12, 2023).
8-K3.205/16/23
San Diego Gas & Electric Company
3.5
Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company effective August 15, 2014.
10-K3.402/26/15
3.6
Bylaws of San Diego Gas & Electric Company (as amended through October 26, 2016).
10-Q3.111/02/16
Southern California Gas Company
3.7
Restated Articles of Incorporation of Southern California Gas Company effective October 7, 1996.
10-K3.0103/28/97
3.8
Bylaws of Southern California Gas Company (as amended through January 30, 2017).
8-K3.101/31/17
EXHIBIT 4 -- INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES
Certain instruments defining the rights of holders of long-term debt instruments are not required to be filed or incorporated by reference herein pursuant to Item 601(b)(4)(iii)(A) of SEC Regulation S-K. Each Registrant agrees to furnish a copy of such instruments to the SEC upon request.
Sempra
4.1
Officers’ Certificate of Sempra, dated as of August 29, 2025, including the form of 6.375% Fixed-to-Fixed Reset Rate Junior Subordinated Note due 2056.
8-K4.108/29/25
EXHIBIT 10 -- MATERIAL CONTRACTS
Management Contract or Compensatory Plan, Contract or Arrangement
Sempra / Southern California Gas Company
10.1*
Letter Agreement from Southern California Gas Company to Sara Mijares dated June 2, 2025.
X
10.2*
Letter Agreement from Southern California Gas Company to Erin Smith dated June 3, 2025.
X
* Portions of the exhibit have been omitted in accordance with applicable SEC rules.
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EXHIBIT INDEX (CONTINUED)
Exhibit NumberExhibit DescriptionFiled or Furnished Herewith
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra
31.1
Certification of Sempra’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
31.2
Certification of Sempra’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
San Diego Gas & Electric Company
31.3
Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
31.4
Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
Southern California Gas Company
31.5
Certification of Southern California Gas Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
31.6
Certification of Southern California Gas Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
X
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra
32.1
Certification of Sempra’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
X
32.2
Certification of Sempra’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
X
San Diego Gas & Electric Company
32.3
Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
X
32.4
Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
X
Southern California Gas Company
32.5
Certification of Southern California Gas Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
X
32.6
Certification of Southern California Gas Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
X
EXHIBIT 101 -- INTERACTIVE DATA FILE
101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data file because its XBRL tags are embedded within the Inline XBRL document.X
101.SCHInline XBRL Taxonomy Extension Schema Document.X
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document.X
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document.X
101.LABInline XBRL Taxonomy Extension Label Linkbase Document.X
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document.X
EXHIBIT 104 -- COVER PAGE INTERACTIVE DATA FILE
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
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SIGNATURES
Sempra:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 SEMPRA,
(Registrant)
  
Date: November 5, 2025By: /s/ Dyan Z. Wold
 Dyan Z. Wold
Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer)

San Diego Gas & Electric Company:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 SAN DIEGO GAS & ELECTRIC COMPANY,
(Registrant)
  
Date: November 5, 2025By: /s/ Valerie A. Bille
 Valerie A. Bille
Senior Vice President, Chief Financial Officer, Controller and Chief Accounting Officer (Duly Authorized Officer)
 
Southern California Gas Company:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 SOUTHERN CALIFORNIA GAS COMPANY,
(Registrant)
  
Date: November 5, 2025By: /s/ Sara P. Mijares
 Sara P. Mijares
Vice President, Controller and Chief Accounting Officer (Duly Authorized Officer)

142

Source: View Original Filing on SEC EDGAR

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